20120629 REMIT FinalReport - European Commission · 5 4.5.2.2. Records of transactions 75 4.5.2.3. List of contracts and derivatives and appropriate de minimis thresholds 75 4.5.2.4

REMITTechnical Advice for settingup a data reportingframework

Final Report

June 2012

REMITTechnical Advice for settingup a data reportingframework

Final Report

June 2012

Technical Advice for setting

2

Date:

29 June 2012

Client name:

European CommissionDirectorate-General for Energy

Directorate B - Energy Markets and Security of Supply

Final Report:

REMIT: Technical Advice for setting up a data reporting framework

Document version:

Final Report

Submitted by:

3

Table of Contents

1. Executive Summary 7

2. Introduction 11

2.1. Project context 11

2.2. Project approach and methodology 12

2.3. Overview on the structure of the report 15

3. Framework for reporting under REMIT 16

3.1. Introduction 16

3.2. Stakeholder groups in energy wholesale markets 17

3.2.1. The role of market participant in REMIT 17

3.2.2. Organisations representing market participants 18

3.3. Interdependencies with financial markets reporting 20

3.3.1. Current reporting requirements 20

3.3.2. Envisaged amendments 21

3.3.3. Reporting channels 22

3.4. Current availability of data 24

3.4.1. Transaction lifecycle 24

3.4.2. Traders and brokers 27

3.4.3. Exchanges 29

3.4.4. NRAs 31

3.4.4.1. Introduction - involvement of NRAs via CEER 31

3.4.4.2. Fragmentation of supervision in the wholesale energy market 31

3.4.4.3. Non-binding statements from the workshop with the NRAs 32

3.5. Electricity TSOs 33

3.5.1. Introduction 33

3.5.2. Data currently reported and/or published by electricity TSOs on an individual basis(fundamental data/transparency provisions) 34

3.5.3. Data readily available (transactional data) 38

3.5.4. Harmonised fundamental data (ENTSO-E transparency platform) 41

3.5.5. Summary on REMIT data currently available 42

3.5.6. ERGEG Advice on Comitology Guidelines on Fundamental Electricity Data Transparency:Data items to be published according to the ERGEG draft 43

3.6. Gas TSOs 52

3.6.1. Introduction 52

3.6.2. Fundamental data published by gas TSOs on an individual basis (transparency data) 53

3.6.3. Harmonised fundamental data 55

4

3.6.4. Disaggregated fundamental /trade data currently held by TSOs 57

4. Definition of requirements for power and gas reporting 59

4.1. Introduction 59

4.2. Traders and brokers 59

4.2.1. Records of transactions 59

4.2.2. List of contracts and derivatives 60

4.2.3. Uniform rules on the reporting of transactions and orders to trade 61

4.2.4. Timing and form for the reporting of transactions and orders to trade 61


4.2.6. Reporting of regulated information (fundamental data) 62

4.2.7. Uniform rules on the reporting of regulated information 62

4.2.8. Timing and form for the reporting of regulated information 62

4.2.9. Further Suggestions 63

4.3. Third party data providers 64

4.3.1. Summary of responses from third party data providers 64

4.4. Exchanges 66


4.4.2. List of contracts and derivatives and appropriate de minimis thresholds 66




4.4.6. Reporting of fundamental data 69



4.5. Transport Data 70

4.5.1. Electricity TSO data 70

4.5.1.1. Summary feedback on future reporting requirements 70

4.5.1.2. Records of transactions 72

4.5.1.3. List of contracts and derivatives 72

4.5.1.4. Uniform rules on the reporting of transactions and orders to trade 72

4.5.1.5. Timing and form for the reporting of transactions and orders to trade 73

4.5.1.6. Reporting channels 73

4.5.1.7. Reporting of fundamental data 73

4.5.1.8. Uniform rules on the reporting of regulated information 73

4.5.1.9. Timing and form for the reporting of regulated information 73

4.5.2. Gas TSO data 74

4.5.2.1. Summary feedback on future reporting requirements 74

5

4.5.2.2. Records of transactions 75

4.5.2.3. List of contracts and derivatives and appropriate de minimis thresholds 75

4.5.2.4. Uniform rules on the reporting of transactions and orders to trade 76

4.5.2.5. Timing and form for the reporting of transactions and orders to trade 76

4.5.2.6. Reporting channels 76

4.5.2.7. Reporting of fundamental data 76

4.5.2.8. Uniform rules on the reporting of fundamental data 77

4.5.2.9. Timing and form for the reporting of regulated information 77

4.5.2.10. Ongoing harmonisation work 77

4.6. NRA view 78






4.6.6. Reporting of regulated information (fundamental data) 81



5. Advice on reporting requirements 84

5.1. Advice on reporting requirements 84






5.1.6. Reporting of fundamental data 100

5.1.7. Uniform rules on the reporting of fundamental data 103

5.1.8. Timing and form for the reporting of fundamental data 103

5.1.9. Gas storage and LNG fundamental data 104

5.2. Phased approach for reporting of trade data 106

5.3. Phased approach for reporting of fundamental data 109

6. Concluding remarks 111

Appendix - Glossary 112

Appendix - REMIT Reporting Document Format 119

OTC trade data format for reporting of Commodity Contracts 119

REMIT Business Acknowledgement 130

REMIT Rejection 131

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Short-Form Reporting of Commodity Contracts 132

Phase 1 Reporting by Power TSOs 133

Phase 1 Reporting by Gas TSOs 137

7

1. Executive Summary

The Regulation on Energy Market Integrity and Transparency (REMIT), adopted by the Council on

10 October 2011, sets up a framework for monitoring energy and financial wholesale energy markets

at a European level. The energy and financial wholesale energy markets affected by REMIT

encompass both derivative markets (which can be executed physically or financially) and spot markets

(where short-term transactions with physical delivery are executed), as well as longer term physical

markets as a specific element.

In the context of further concretisation of REMIT, the Commission has appointed a consortium

comprising PwC and Ponton to provide technical assistance in setting up the complex reporting

framework set out in Article 8.

In particular, advice was sought on setting up a framework for an effective data reporting scheme as

required by REMIT, which should set out uniform rules for reporting, including the content, timing,

and format of reportable data.

As part of this work, workshops were held with representatives of a number of stakeholder categories

(including traders and brokers, intermediaries/ third party solution providers, exchanges, gas TSOs,

electricity TSOs, National Regulatory Authorities (NRAs)). Input to our project was also provided by

means of stakeholder questionnaires and Steering Group meetings with DG Energy and ACER

representatives.

As a result of the analysis undertaken and the feedback received, the following key recommendations

in relation to developing a framework for an effective data reporting schemes in the context of REMIT

were provided.

Transaction reporting

Records of transactions

Terminology concerning transaction types:

o Develop a non-exhaustive list of transaction types and transaction stages as part of

the explanatory documents accompanying the further implementation of REMIT to

specify the reporting obligation

o Include LNG and storage transactions and derivative transactions relating to LNG

and storage in the list of wholesale energy products

Terminology concerning transaction lifecycle stages:

o Specify in further explanatory documents the three transaction stages of order,

contract and scheduling/ nomination in such a way that the reporting obligation

under REMIT principally includes these three stages for each transaction.

List of contracts and derivatives

Geographical scope of reporting obligation

o Specify a list of transmission systems for power and gas in the European Union as a

basis for the definition of the reporting obligation.

o Define the reporting obligation as being applicable for all gas and power transactions

(and derivatives relating to such transactions) which may result in delivery,

transportation rights, or storage rights in a transmission system under the operation

of a power/ gas TSO, SSO, or LSO included in the previous list.

ACER product taxonomy

8

o Define a standard product taxonomy which is binding for the industry in order to

categorize transactions by their product types. Contrary to proprietary energy product

codes on exchanges, this ACER product taxonomy will not be a list of codes such as

“F0BM” or “DBF Nov-12”, the proprietary codes for monthly base load on EEX and

APXENDEX, respectively. Split the product taxonomy into separate dimensions, each

dimension having a finite and well defined number of possible values.

Uniform rules on the reporting of transactions and orders to trade

Coding scheme for market participants from ongoing ACER registration procedures

o Use the EIC code as a basis for the ACER code, used to identify market participants in

the REMIT reporting format or at least supply as a secondary code

Delimitation of markets with different tenure

o Specify in further explanatory documents that balancing markets are within the

overall reporting obligation but do not make balancing transactions a part of an initial

reporting phase

Specification of reporting obligation of market participants in the transaction stages

o By transaction type, the respective stages of a transaction and for both parties

involved in a transaction clarify the reporting obligations of market participants.

Reporting obligations for the order and contract stage:

o Split the overall reporting obligations for commodity transactions into long form and

short form reporting from the start of the reporting regime.

o Publish a list of intermediaries and request explicitly that at minimum all commodity

transactions processed by these intermediaries need to be reported in long form

(“white list”). Keep such an intermediary list extendable by giving notice hereof in a

versioned ACER guidance document.

o Apply the REMIT Reporting Document Format for commodity, transport and storage

transactions while mentioning that the scope of long form reporting may be adjusted

by issuing new versions of the REMIT reporting standard in case further

standardization is achieved.

Reporting obligations for the Scheduling/nominations stage:

o Apply the REMIT Reporting Document Format for the scheduling/nominations

transaction stage of all gas and power transactions from the start of the reporting

regime.

Timing and form for the reporting of transactions and orders to trade

Define reporting obligation for wholesale energy transactions in all three major transaction

stages: order, contract, and scheduling/nomination. Reporting in the latter two transaction

stages (contract and scheduling/nomination) should be implemented in phase 1, with

reporting in the order stage to follow in phase 2.

Define the cycle for long form reporting of the order and contract transaction stage for all

commodity, transport and storage transactions to be T+1, i.e. by close of the following

business day.

Define the cycle for reporting of the scheduling/nomination transaction stage for all

commodity, transport and storage transactions to be T+1, i.e. by close of t day.

Define the cycle for short form reporting to be at maximum monthly, i.e. by close of the first

business day in the calendar month for the preceding calendar month.

Consider wholesale energy transaction lifecycle events such as amendments, cancellations, or

novations as out of scope for reporting at least in phase 1.

Provide a way for reporting parties to communicate gross errors such as order of magnitude

errors made in previous reports of wholesale energy transactions to ACER.

9

Reporting channels

Define criteria and a procedure on how to register centrally with ACER as “Certified Self-

Reporting Party” for market participants and as “Registered Reporting Mechanism” as third-

party service provider and accept reporting only from such registered organizations; foresee

an adjusted registration process for TSOs.

Fundamental data reporting:

Reporting of fundamental data

Reporting of fundamental data should be undertaken via central transparency platforms, to

fulfil relevant transparency requirements. Collection of disaggregated fundamental data

should be undertaken via the same transparency platforms, provided appropriate

confidentiality and data ownership provisions are in place. In the interim, collection of limited

selected capacity information from market participants should be via ARIS.

Uniform rules on the reporting of fundamental data

Clarify role of TSOs as data aggregators and the requirement to report disaggregated

fundamental data as part of drafting of implementing acts.

Timing and form for the reporting of fundamental data

Introduce a requirement to report fundamental data upon change, with a maximum frequency

of daily reporting.

Gas storage and LNG fundamental data

Reporting of fundamental data should be undertaken via central transparency platforms to

fulfil relevant transparency requirements. Collection of disaggregated fundamental data

should be undertaken via the same transparency platforms, provided appropriate

confidentiality and data ownership provisions are in place. In the interim, collection of

limited selected capacity information from market participants should be via ARIS.

Phased approach for reporting

Phased approach for reporting of trade data

Follow a phased approach for the reporting of wholesale energy product transactions to reflect

the current amount of standardization in the market, taking into account the economic impact

of the implementation.

Indicate the duration of phase 1 (and of any further phases as may be required) as being

around two years. Sufficient clarity on the framework for subsequent phases should be

provided initially.

As further clarity becomes available following the implementing acts, further non-binding

guidance can be provided to market participants

Phased approach for reporting of fundamental data

Reporting of fundamental data should follow existing and proposed regulations. Develop

harmonised transparency platforms to set the timeline for introduction of fundamental data

reporting. Consider introduction of central transparency platforms for storage, LNG and EU

production data.

Consistent with the approach outlined in the previous section define a clear timeline for the

introduction of Phase 2, which could estimated to be around 2 years. If central collection of

fundamental data is not introduced by TSOs (and other relevant market participants) within a

10

defined timescale, introduce a REMIT reporting obligation and format in order to collect

fundamental data directly from participants in ARIS as part of Phase 2.

11

2. Introduction

2.1. Project context

The Regulation on Energy Market Integrity and Transparency (REMIT), adopted by the Council on

10 October 2011, sets up a framework for monitoring energy and financial wholesale energy markets

at a European level. The energy and financial wholesale energy markets affected by REMIT

encompass both derivative markets (which can be executed physically or financially) and spot markets

(where short-term transactions with physical delivery are executed), as well as longer term physical

markets as a specific element.

Whilst to date energy market monitoring practices have been Member State and sector specific,

efficient market monitoring at an EU level has been identified as a key requirement for detecting and

monitoring market abuse.

Key objectives of REMIT are:

Prohibition of insider trading (direct use of insider information, disclosure of insider

information to third parties, recommendation to third parties to trade energy products on the

basis of insider information) and the obligation to publish insider information (Art. 3 and Art.

4)

Prohibition of market manipulation (Art.5)

Establishment of a framework for monitoring wholesale energy markets at a European level in

order to effectively detect and deter market abuse and manipulation (Art.7)

Pursuant to Article 8 of REMIT, ACER shall be provided with a record of wholesale market

transactions, which include contracts for the supply of natural gas or electricity and their

derivatives as well as contracts relating to the transportation of natural gas or electricity in the

Union and their derivatives as defined in Article 2.

In addition, market participants are required to provide ACER and national regulatory authorities

with information related to the capacity and use of facilities for production, storage, consumption

or transmission of electricity or natural gas as well as LNG facilities. This includes planned or

unplanned unavailability of these facilities.

The required information may be delivered by either:

The market participant;

A third party acting on behalf of the market participant;

A trade reporting system;

An organized market, a trade-matching system, or other person professionally arranging

transactions;

Registered or recognized trade repositories;

A competent authority that has received this information in accordance with MiFID.

In the context of further concretisation of REMIT, the Commission has appointed a consortium

comprising PwC and Ponton to provide technical assistance in setting up the complex reporting

framework set out in Article 8. The following sub-section summarises the approach to provide this

assistance.

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2.2. Project approach and methodology

The figure below outlines the key steps undertaken in order to meet the project objectives, which were

identified as:

• Advice on setting up a framework for the effective data reporting scheme as required

by REMIT, which should set out uniform rules for reporting, including the content, timing,

and format of reportable data

• Technical recommendations on how such data sharing should be organised and how

data security can be ensured

• Technical recommendations related to ACER making part of the information it receives

publicly available

Figure 1 Key project work steps

At the initial project kick-off meeting with the European Commission, the following principles were

agreed upon for guidance in the execution of this project:

Interaction with and input from ACER will be important – we have had direct meetings with

the ACER team, and ACER has been included as part of the project Steering Group. In

Preparation of“data inventory”

Stakeholderworkshops

1 2

Definition ofelectricityreporting

requirements

3

3a Definition ofIT concept,data sharingandsecurity 4

43b

Stakeholderreview

54

Data Reporting

- Trade Data- Transportation Contract Data

- Fundamental Data

Data Sharingand Security

Publication andtransparency

Legal compliance

Definition ofgas reportingrequirements

3b

Scope definition of transactional data

Sources of transactional data and frequency of reporting

Requirements analysis and IT concept

Work steps

Key issues

Conceptual pillars

13

addition, ACER will be providing comments on the Preliminary Advice to be considered in the

drafting of Final Advice.

Where possible existing stakeholder interaction channels should be used and work

undertaken to date should be considered – we have organised our stakeholder interaction via

existing industry groups (see Step 2) and have asked these groups to assist us in the

identification of relevant existing initiatives.

Synergies with other projects and workstreams will need to be considered – we have

identified these jointly with key stakeholder groups and have prioritised approaches which

capture synergies with existing workstreams in the respective stakeholder groups.

Step 1: Preparation of data inventory; Step 2: Stakeholder workshops

Key activities undertaken as part of this first phase of work have included:

Research of selected existing sources

Interaction with industry representatives, including preparation of stakeholder

questionnaires and identification of key issues

Stakeholder workshops

Circulation of stakeholder questionnaires

The outcome of this work has been the development of an overview of the current data structures and

sources. A draft set of questionnaires was prepared for the relevant stakeholder categories agreed

upon with DG Energy (Traders and Brokers, Intermediaries1, Exchanges, Gas TSOs, Electricity TSOs

and National Regulatory Authorities), and discussed as part of workshops with each stakeholder

category.

Following the workshops, an updated version of the questionnaire was circulated to stakeholders, who

provided responses that in some cases were coordinated by a stakeholder representative organisation,

in other cases were submitted directly by stakeholders. The table below summarises the workshops

that have been held and the stakeholder responses received.

1 An additional workshop for Intermediaries (not planned initially) was undertaken on request of DGEnergy

14

Table 1 Overview of stakeholder workshops and questionnaire responses

Workstream Workshop

held on

Individual

responses

due by

Aggregate

response

due by

Individual

responses

received

Aggregate

response

received?

Notes

Traders and

Brokers

29th March 12th April 30th April RWE,

Vattenfall,

E.ON

Yes Aggregate response

organised by EFET

representing views of

EFET, Eurogas and

Eurelectric

Intermediar-

ies

19th April 3rd May N/A Openlink,

Triple Point,

ICIS Heren,

EFETnet ,

Trayport

(confidential

response

sent directly

to DG

Energy)

N/A Additional workshop

initially not planned.

Outstanding: CME, ICE,

Sungard, DTCC, Argus

Exchanges 19-20th

March

13th April 20th April OCE Yes Consolidated response

received from Europex

Gas TSOs 10th April 25th April Mid May 23

responses

received

Yes All answers sent directly to

PwC. Aggregate response

by ENTSOG prepared only

on selected questions,

received on 9th May

Electricity

TSOs

28th March 12th April 26th April Admie

(Greek TSO)

Yes Consolidated response

received on 10th May

NRAs 28th March 13th April 27th April 2 individual

responses

(Portuguese

and Italian

NRAs)

Yes Consolidated response

received on 3rd May

Step 3: Definition of reporting requirements; Step 4: IT concept for reporting

Based on the results of previous steps, including but not limited to stakeholder questionnaire

responses, we have developed an overview of current data availability and of the emerging

requirements for power and gas reporting based on stakeholder feedback. Further to this, we have

derived our own recommendations on the concretisation of future reporting requirements under

15

REMIT. The proposed reporting structure includes recommendations for the data content to be

reported by the stakeholders to ACER as well as the required regularity of data reporting.

On the basis of this, a concluding recommendation is given regarding scope and regularity of the

future reporting obligations under REMIT including a REMIT Reporting Document Format as a

foundation for the design of a future data repository – provisionally named ARIS (Acer REMIT

Information System).

Step 5: Stakeholder review

Stakeholder input has been provided as part of this project largely via stakeholder feedback from

workshops as well as responses to the questionnaires. Steering group meetings have also been

undertaken over the course of the project to share ideas with representatives from DG Energy and

ACER. In addition, bilateral stakeholder meetings have been conducted by project team members

with selected stakeholder representatives to receive additional stakeholder input.

2.3. Overview on the structure of the report

In accordance with these work steps, the remainder of this document is structured as follows:

Section 3 provides an overview of the framework for reporting under REMIT, looking at, for

example, current data availability and regulatory environments

Section 4 outlines the feedback from stakeholders on envisaged requirements for power and

gas reporting

Section 5 outlines our recommendations on the envisaged requirements for power and gas

reporting

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3. Framework for reportingunder REMIT

3.1. Introduction

This section looks at the existing availability of data relevant for the reporting obligations placed on

market participants, classified into two categories derived from REMIT as outlined below.

“Trade data”

Under Art. 8 (1) of REMIT, market participants (or a person or authority on their behalf as defined by

Art. 8 (4)) are required to provide ACER with a “record of wholesale energy market transactions

including orders to trade”. In particular, the following is required: “precise identification of the

wholesale energy products bought and sold, the price and quantity agreed, the dates and times of

execution, the parties to the transaction and the beneficiaries of the transaction and any other

relevant information”.

Art. 2 (4) of REMIT provides a definition of “Wholesale energy product” as the following contracts

and derivatives, irrespective of where and how they are traded: (a) contracts for the supply of

electricity or natural gas where delivery is in the Union; (b) derivatives relating to electricity or

natural gas produced, traded or delivered in the Union; (c) contracts relating to the transportation

of electricity or natural gas in the Union; (d) derivatives relating to the transportation of electricity

or natural gas in the Union".

“Fundamental data”

Art. 8 (5) of REMIT indicates that “Market participants shall provide ACER and national regulatory

authorities with information related to the capacity and use of facilities for production, storage,

consumption or transmission of electricity or natural gas or related to the capacity and use of LNG

facilities, including planned or unplanned unavailability of these facilities, for the purpose of

monitoring trading in wholesale energy markets." To review the availability of such data, the

following stakeholder categories have been assessed in particular:

Traders and brokers (gas and electricity)

Exchanges (gas and electricity)

Transmission System Operators (gas and electricity)

In undertaking this analysis, it is important to take into account the role of existing channels of data

collection and aggregation and other regulatory obligations (such as current reporting obligations

under MiFID, and potential reporting obligations under EMIR and MiFIR). These considerations are

particularly relevant in the context of the provision included in REMIT Art.8 (3), which clarifies that

market participants who have already reported transactions in accordance with MiFID or applicable

EMIR regulations shall not be subject to double reporting obligations relating to those transactions.

For each stakeholder category outlined above, the following types of data have been considered:

17

Trade data and fundamental data, as defined by REMIT and currently available to the

stakeholder category, outlining separately: a) data currently reported and/or published and b)

data readily available from stakeholders.

Data that is potentially required by REMIT and relevant to the responsibilities of the

stakeholder category, but not (currently) available, including an explanation of issues with the

availability of such data.

Data required in the context of different regulatory regimes or requirements (e.g. by financial

regulations such as MiFID, or fundamental data published in the context of Electricity

Regulation2 and Gas Regulation3), which could overlap with REMIT requirements.

The availability of data from the various stakeholder categories has been derived from the

questionnaire responses provided as part of the individual stakeholder workstreams, as well as by

research on publicly available data and bilateral interactions with various stakeholder representatives.

The key objective is to provide an overview of the current reporting framework, including the relevant

data available, in order to support the definition of the gas and power reporting requirements outlined

in the following section. For data currently reported, we have also considered the frequency of

reporting and granularity of data where relevant.

3.2. Stakeholder groups in energy wholesale markets

3.2.1. The role of market participant in REMIT

Market participants in the sense of REMIT are defined in Art. 2 (7) of REMIT as persons, including

TSOs, who enter into transactions, including the placing of orders to trade, in one or more wholesale

energy markets. A reporting requirement arises according to Art. 8 (1) of REMIT when a wholesale

energy market transaction is conducted. Simple involvement with a wholesale energy market

product as such does not trigger a reporting requirement. A reporting requirement depends on

whether or not the transaction took place at a wholesale energy market, i.e. a market defined in Art. 2

(6) of REMIT where wholesale energy products specified by Art. 2 (4) of REMIT are traded. According

to Recital (5) of REMIT, wholesale energy markets include, inter alia, regulated markets, multilateral

trading facilities, and over-the-counter (OTC) transactions, as well as bilateral contracts, either direct

or through brokers. This leads to a wide definition of wholesale energy markets.

Key market participants are therefore traders who are active on gas and power markets. The focus is

on traders because they regularly base their buy and sell decisions for commodity, transport, and

storage contracts on their own price expectations. Thus, they may have an interest in moving prices in

a direction which suits the overall commercial result of their trading activity.

Producers of gas and operators of power plants are considered here to be market participants,

assuming that they either pass on their production to their in-house trading unit or are directly active

on markets themselves (and would then be treated under REMIT in the same way as traders would,

Art. 2 (7) of REMIT). Having said this, producers may be the best (and sometimes only) source of

fundamental data according to Art. 8 (5) and of inside information like block closures leading to the

unavailability of production facilities (Art. 4 (1) of REMIT).

2 Regulation (EC) n. 714/20093 Regulation (EC) n. 715/2009

18

Transmission System Operators (TSOs) play a crucial role in providing gas and power

infrastructure, selling capacity contracts so that traders can deliver energy contracts physically. In

addition, TSOs operate balancing markets as a means of securing that gas and power networks can be

operated within predefined technical limits while all contractual obligations between traders are

fulfilled and the security of supply is guaranteed. Therefore, they are explicitly named as market

participants in Art. 2 (7) of REMIT.

Electricity TSOs are legally defined as "a natural or legal person responsible for operating, ensuring

the maintenance of and, if necessary developing the transmission system in a given area and, where

applicable its interconnections with other systems, and for ensuring the long-term ability of the

system to meet reasonable demands for the transmission of electricity" (Art. 2 (4) of Electricity

Directive4).

Gas TSOs are legally defined as "a natural or legal person who carries out the function of transmission

and is responsible for operating, ensuring the maintenance of, and, if necessary, developing the

transmission system in a given area and, where applicable, its interconnections with other systems,

and for ensuring the long-term ability of the system to meet reasonable demands for the transport of

gas" (Art. 2 (4) of Gas Directive5).

As regards storage system and LNG terminal operators (SSOs, LSOs), Recital (18) of REMIT

states that efficient market monitoring also requires regular and timely access to records of

transactions as well as access to structural data on capacity and use of facilities for storage. However,

in Art. 2 (4) of REMIT where “wholesale energy products” are defined, the definitions are restricted to

contracts for the supply of electricity or natural gas or contracts relating to the transportation of

electricity or natural gas and to derivatives regarding the production of these commodities or their

transportation. Whilst storage contracts are not explicitly included in the definition of “wholesale

energy products”, SSOs and LSOs are important market participants who act as service providers to

other market participants (e.g. traders and shippers) in a similar way as TSOs do, apart from not

operating balancing markets and not becoming party to commodity transactions.

End users or “final customers” as they are called in REMIT are, as a general rule, outside the

scope of REMIT. It could be questioned whether a contract concluded by an end user directly with a

supplier in the form of a full supply contract would also be subject to transaction reporting.

Transaction reporting requirements are triggered in general by wholesale energy market

transactions, which should not be typical for end users. It is stated that contracts for the supply and

distribution of electricity or natural gas for the use of final customers are not wholesale energy

products (Art. 2 (4) REMIT). However, a contract with an end user can also qualify as wholesale

energy product Contracts for supply to final customers exceeding the threshold of 600 GWh per

annum are treated as wholesale energy products and make the holder of the contract a market

participant under REMIT.

3.2.2. Organisations representing marketparticipants

Whilst an accurate estimate of the number of potential sources of data is difficult to provide, we

believe that a reasonable approximation can be achieved by counting the individual members of

4 EC Directive 2009/725 EC Directive 2009/73

19

industry associations which have been established to represent particular stakeholder groups. Below is

an overview of the organisations that have been involved as part of this project:

Council of European Energy Regulators (CEER) – not-for-profit association set up by

independent energy regulators of Europe to provide a forum for cooperation

European Network of Transmission System Operators for Electricity (ENTSO-E) – represents

all electric TSOs in the EU and others connected to their networks, for all regions, and for all

their technical and market issues

European Network of Transmission System Operators for Gas (ENTSOG) – works to ensure

the optimal management, coordinated operation, and sound technical evolution of the

European natural gas transmission network and to ensure early progress towards the single

market

Eurogas – a not-for-profit organisation representing companies, national federations and

associations involved in the supply, trading, and distribution of natural gas and related

activities such as storage and liquefied natural gas

Eurelectric – the sector association which represents the common interests of the electricity

industry at a pan-European level

European Federation of Energy Traders (EFET) – a group of energy trading companies from

27 European countries dedicated to stimulate and promote energy trading throughout Europe

The Association of European Energy Exchanges (EUROPEX) – a not-for-profit association

that represents the interests of the exchange based wholesale markets for electrical energy,

gas, and environmental markets

The memberships of these organisations by country are listed in the figure below. In total, these

organisations have 279 members across the 27 EU member states and 7 other accession states and

single market participants. These are summarised by country in the chart below. The UK and

Germany have the highest number of memberships, with 34 companies represented, primarily due to

the high number of companies engaged in energy trading, while the average number is 7.

20

Figure 2 Membership of organisations by country

3.3. Interdependencies with financial marketsreporting

3.3.1. Current reporting requirements

Investment firms are obliged to report transactions with financial instruments admitted to be traded

in a regulated market as quickly as possible and at the latest by the close of business of the following

working day - regardless of whether the trade took place in a regulated market or not. This obligation

imposed by MiFID, which has been in force since 2007, had to be implemented by each national

legislator.6 The data to be reported was specified directly via the Regulation (EC) No 1287/2006

6 Art. 25 Subsec. 3 MiFID.

0 5 10 15 20 25 30 35

Bosnia

Montenegro

Turkey

Macedonia

Malta

Serbia

Cyprus

Estonia

Iceland

Latvia

Lithuania

Bulgaria

Luxembourg

Hungary

Ireland

Romania

Denmark

Finland

Greece

Norway

Poland

Slovakia

Portugal

Slovenia

Czech Republic

Belgium

Netherlands

Spain

France

Austria

Switzerland

Italy

Germany

UK

21

implementing MiFID. The annex to the aforementioned regulation shows 23 fields containing

information which must be reported.7

Since the reporting requirement is restricted to financial instruments, the spot market as well as

individualised forward contracts with envisaged physical delivery are outside MiFID’s scope of

reporting. According to MiFID, financial instruments in electric power and gas can be the following:

Options, futures, swaps, forward rate agreements, and any other derivative contract that must

be settled in cash or may be settled in cash at the option of one of the parties (other than by

reason of a default or other termination event)

Options, futures, swaps, and any other derivative contract that can be physically settled,

provided that they are traded on a regulated market and/or a Multilateral Trading Facility

Options, futures, swaps, forwards, and any other derivative contract that can be physically

settled not otherwise mentioned in the bullet above and not being for commercial purposes,

which have the characteristics of other derivative financial instruments, having regard to

whether, inter alia, they are cleared and settled through recognised clearing houses or are

subject to a regular margin call.8

Numerous participants in the energy market who are active in the financial markets, e.g. via energy

derivatives, would qualify according to their activities as investment firms. However, they benefit from

exemptions regarding the license requirements especially designed for utilities9 and commodity

traders10. Thus, they do not qualify as investment firms to which the reporting obligation applies.

Therefore, the applicability of reporting requirements under MiFID for transactions in the energy

sector is currently restricted.

3.3.2. Envisaged amendments

Amendments in the reporting requirement regarding financial instruments will follow the

implementation of EMIR and the revision of MiFID (MiFID II) introducing MiFIR.

MiFID applies currently to a narrower set of companies than what is expected after the revised

financial market regulations MiFID II and MiFIR enter into force. In the interim period, between

the reporting obligations under REMIT entering into force and EMIR entering into force in 2013,

and taking the extension of MiFID reporting obligations foreseen in 2015 into account, more trade

data will have to be reported to ACER as no other reporting to competent authorities that can fulfil

REMIT reporting obligations is required.11

According to EMIR, counterparties and central clearing counterparties have to ensure that the details

of any derivative contract they have concluded and any modification or termination of the contract is

reported to a trade repository no later than the following day.12 The term “derivative contract” covers

derivative contracts as mentioned above under 1.2.insofar as they are defined in MiFID as financial

7 Art. 13 EU Regulation 1287/2006 and Tab. 1 of Annex 1.8 MiFID Annex I, Section C (5)-(7).9 Art. 2 (1) (i) MiFID.10 Art. 2 (1) (k) MiFID.11 Recital (19) REMIT.12 Art. 9 (1) EMIR.

22

instruments.13 Therefore, for example, individualised OTC forward contracts regarding the physical

delivery of power and gas are outside the scope of EMIR.

A trade repository has to explicitly grant access to information to ACER to fulfil its tasks.14 It is

expected that EMIR will come into force on 1.1.2013.

As a general consequence of MiFID II, all organised trading shall be conducted on regulated trading

venues. Therefore, all transactions in financial instruments will need to be reported to competent

authorities.15 As an exception, there will be no reporting required for financial instruments not

admitted to trading or traded on an MTF (Multilateral Trading Facility) or an OTF (Organized

Trading Facility), to financial instruments whose value does not depend on that of a financial

instrument admitted to trading or traded on an MTF or OTF nor to financial instruments which do

not or are not likely to have an effect on a financial instrument admitted to trading or traded on an

MTF or OTF.16 The reports to the competent authority will either be conducted by the investment firm

itself, an authorised reporting mechanism (ARM) on its behalf, or by an MTF or OTF whose systems

are used for the execution.17

The amount of contracts in electric power or gas to be reported will also increase due to an expansion

of the definition of financial instruments. Derivative contracts that can be physically settled will also

be regarded as financial instruments provided they are traded on a regulated market, an OTF, or an

MTF, in contrast to the current definition focussing on trading on regulated markets and MTFs.18

Moreover, the exemptions that are important for definition as an investment firm as mentioned above

will be restricted. More energy trading entities are expected to qualify as investment firms and hence

will be subject to reporting requirements, especially if they are involved in trading on own account.19

MiFID II is expected to come into force 2015.

3.3.3. Reporting channels

MiFID

Under MiFID, all reportable transactions are to be reported by the investment firm itself, a third party

acting on its behalf, or by trade matching or reporting systems approved by the competent authority,

or by the regulated market, or an MTF through whose systems the transaction was completed.20 In the

U.K., the FSA introduced transaction reporting systems collectively referred to as Approved Reporting

Mechanisms (ARMs) to manage transaction reporting for third parties under MiFID. There is an

application fee of £ 100,000 for firms seeking to become an ARM. The amount is used for approving

systems and for linking them with the transaction monitoring system.21 These ARMs operate beside

13 Art. 2 (2) EMIR.14 Art. 81 (3) j EMIR.15 Explanatory Memorandum MiFID II p. 5.16 Art. 23 (2) MiFIR.17 Art. 23 (6) MiFIR Proposal.18 Annex I Section C (6) MiFID II Proposal.19 Art. 2 (1) MiFID II Proposal.20 Art. 25 (5) of MiFID. According to article 23 (6) of the MiFIR transactions are to be reported by the investment firm itself,

an ARM acting on its behalf or by the regulated market or MTF or OTF through whose systems the transaction wascompleted. Trade-matching or reporting systems, including trade repositories registered or recognised in accordance withEMIR, may be approved by the competent authority as an ARM.

21 Http://www.fsa.gov.uk/doing/regulated/returns/mtr/arms.

23

regulated markets and MTFs, which can also provide this service with the difference though that they

do not have to apply at the FSA.

Trade matching or reporting systems under MiFID have to comply with specific requirements detailed

in Art. 12 of Regulation (EC) No 1287/2006 implementing MiFID. The methods by which the reports

of transactions in financial instruments are made shall satisfy the following conditions:

They ensure the security and confidentiality of the data reported;

They incorporate mechanisms for identifying and correcting errors in a transaction report;

They incorporate mechanisms for authenticating the source of the transaction report;

They include appropriate precautionary measures to enable the timely resumption of

reporting in the case of system failure;

They are capable of reporting the information required under Article 13 in the format required

by the competent authority and in accordance with this paragraph, within the time limits set

out in Art. 25 (3) of MiFID.22

EMIR

Under EMIR, counterparties and CCPs shall ensure that the details of any derivative contract they

have concluded and any modification or termination of the contract is reported to a trade repository.

Reporting obligations may be delegated by counterparties or CCPs to another entity.23 An entity or its

employees that report the details of a derivative contract to a trade repository on behalf of a

counterparty, in accordance with this Regulation, should not be in breach of any restriction on

disclosure of information imposed by that contract or by any legislative, regulatory or administrative

provision.24

According to article 51 (1) of EMIR, a trade repository shall register with ESMA for the purposes of

fulfilling reporting obligations. EMIR sets out general and specific requirements to be fulfilled by

trade repositories.

According to Article 64 of EMIR, trade repositories shall among others:

Have robust governance arrangements;

Establish adequate policies and procedures sufficient to ensure its compliance with all the

provisions of EMIR;

Maintain and operate adequate organisational structure to ensure continuity and orderly

functioning of the trade repository in the performance of its services and activities;

Employ appropriate and proportionate systems, resources, and procedures;

Have a senior management and board of sufficiently good repute and expertise to ensure the

sound and prudent management of the trade repository;

Publicly disclose the prices and fees associated with services provided under EMIR.

In addition to the more general requirements listed above, trade repositories shall among others

adhere to the following more specific requirements as to operational reliability and safeguarding.

Trade repositories shall:

22 Art. 12 (1) of Regulation (EC) No 1287/2006.23 Recital (24) and Art. 6 (1) of EMIR.24 Recital (24) and Art. 6 (3) of EMIR.

24

Identify sources of operational risk and minimise them through the development of

appropriate systems, controls and procedures. Such systems shall be reliable and secure and

have adequate capacity to handle the information received25;

Establish, implement, and maintain an adequate business continuity policy and disaster

recovery plan aiming at ensuring the maintenance of its functions, the timely recovery of

operations, and the fulfilment of the trade repository's obligations. Such a plan shall at least

provide for the establishment of backup facilities26;

Ensure the confidentiality, integrity, and protection of the information received for reporting

purposes27;

Take all reasonable steps to prevent any misuse of the information maintained in its system.

Trade repositories under EMIR are comparable with REMIT reporting channels as both function as an

aggregator and should provide the respective supervising authority ESMA or ACER with data.

Different from MiFID and REMIT, only EMIR foresees that the supervisory authority is provided with

data exclusively from aggregators, insofar as trade repositories are available.28

3.4. Current availability of data

3.4.1. Transaction lifecycle

We use the term “trade data” to refer to data relating to individual gas and electricity commodity

transactions (both primary energy products and derivatives). In addition, data related to capacity

booking and use (i.e. nominations) at an individual shipper/trader level, as well as data on secondary

traded capacity is included in the category of trade data (although in some sections of this document

we refer to it separately as “transportation contract data”). Trade data also comprises data on

commodity transactions undertaken by Transmission System Operators (TSOs) for network

balancing.

In order to provide further context for our recommendations on data reporting and sharing, we have

outlined below the deal ‘lifecycle’ as applicable firstly to standard commodity transactions and

secondly to contracts with optionality.

For commodity contracts, the key variables of price, volume, and timing of deliveries are usually

specified within the contract terms – exceptions include contracts with flexibility or optionality;

however, these are generally non-standard transactions. For further consideration, it is helpful to refer

to the split between trading and balancing markets and explain the different time periods in which the

energy markets are usually split. Exact definitions vary from country to country based on the

individual provisions of the applicable network code.

25 Article 65 (1) EMIR Proposal.26 Article 65 (2) EMIR Proposal.27 Article 66 (1) EMIR Proposal.28 Article 6 (2) EMIR Proposal.

25

Figure 3 Transaction lifecycle

Participation in the bilateral markets (i.e. the forward/futures contract market and the short-term

bilateral markets) and the balancing markets (i.e. offer/bid submission for balancing energy) can thus

be considered separate and are shown in the four main stages of a transaction lifecycle in the

illustration attached.

The dotted line in the illustration is the point in time for final notification of physical delivery defined

when market participants notify the System Operator of their intended final physical position. This

may be set e.g. for one hour ahead of real time for delivery.

The bilateral contracts markets for firm delivery of gas and electricity operate from a year or more

ahead of real time (i.e. the actual point in time at which electricity is generated and consumed)

typically up to 24 hours ahead of real time. The markets provide the opportunity for a seller and buyer

to enter into contracts to deliver/take delivery, on a specified date, of a given quantity of electricity or

gas at an agreed price. Transactions may be arranged OTC, via brokers, or via exchanges. In the OTC

market, participants have complete freedom to agree contracts of any form, whereas transaction

platforms and exchanges follow a standardization approach. They are intended to reflect trading over

extended periods and represent the majority of trading volumes. The market operates typically from

one up to several years ahead of real time.

Short-term markets for gas and power tend to be concentrated in the last 24 hours ahead of delivery.

Markets are in the form of transaction platforms or screen-based exchanges where participants trade a

series of standardised blocks of electricity or gas (e.g. the delivery of x MWh over a specified period

during the next day). Such platforms enable sellers and buyers to fine-tune their rolling trade contract

positions as their own demand and supply forecasts become more accurate as real time is approached.

One or more published reference prices are available to reflect trading in such markets.

Balancing markets are operated from the notification point in time through to real time and are

typically managed by Transport System Operators. They exist to ensure that supply and demand can

26

be continuously matched or balanced in real time. Markets are operated with the System Operator

acting as the sole counterparty to all transactions. The TSO purchases offers, bids, and other balancing

services to match supply and demand and resolve transmission constraints, and thereby balance the

system.

Capacity contracts will usually specify price and maximum or average volumes, however the timing

of delivery is, in effect, an option retained by the buyer. Delivery is usually confirmed, or nominated,

under a defined nominations process which varies according to the contract type – thus adding an

additional stage to the deal lifecycle. Gas transportation, as detailed below, is one of the most

common forms of standard capacity contract; however, capacity contracts can also relate to the supply

of power, and a similar contract form (take or pay) to gas supply.

Typically, transportation capacity is allocated via a primary allocation mechanism, when a

Transmission System Operator makes a defined volume of capacity that can be booked by market

participants available. This allocation can be undertaken by various mechanisms, including auctions,

open subscription windows, pro-rata mechanisms, first-come first-served mechanisms, and

combinations of the above.

In addition, capacity may be offered as firm or interruptible capacity, and can be offered for different

lengths of time, depending on the characteristics of the allocation process (e.g. annual, quarterly,

monthly, daily and, in some cases, within-day).

Whilst capacity provides the right to use, the users of such capacity rights are required to schedule or

nominate the amount of commodity they intend to flow (booking capacity can be seen as purchasing

an option to use the network; this option is then exercised later in the scheduling or nominations

stage). Shippers can nominate capacity in advance and during the day of delivery, and different

scheduling/nomination rules and formats are used across European countries. Other data that is

available as part of the “lifecycle” include data on network balancing (which again varies significantly

across countries depending on the respective gas or power balancing market mechanism adopted) and

settlement data, which is collected after the end of the delivery day.

The figure below summarises the key elements of the capacity “lifecycle”.

Figure 4 Capacity lifecycle

3.4.2. Traders and

Contributions to this report were made by the members of three trade

the trade organisations themselves: EFET, EUREL

The European Federation of Energy Traders (EFET) is a non

the conditions of energy trading in Europe and to promote the development of a sustainable and

liquid European wholesale market. EFET’s vi

throughout Europe, in which traders efficiently intermediate in the value chain on the basis of clear

wholesale price signals, thereby optimising supply and demand and enhancing security of supply, to

the overall long-term benefit of the economy and of society”. EFET represents about 120 companies

trading in Europe, primarily large companies with a high number of energy wholesale transactions. A

fair share of EFET members are asset

commodity and thus energy wholesale trading like Deutsche Bank or JPMC are well represented in

EFET too. The major OTC brokers are all EFET members

and brokers as far as a functioning OTC market is concerned, thus their responses could be bundled

through EFET.

The Union of the Electricity Industry (EURELECTRIC) is a sector

association representing the common interests of the electricity industry at

EURELECTRIC has over 30 full members representing the electricity industry in 33 countries. The

direct members of EURELECTRIC are the national electricity associations, e.g. Österreichs E

Wirtschaft for Austria, FEBEG for Belgium,

association does not exist, the leading national electricity company is a direct member of

EURELECTRIC instead. In contrast to EFET, it may be said that EURELECTRIC represents the

interests not only of traders, but also of generators and medium to small traders / distributors like the

German Stadtwerke.

EUROGAS is a non-profit organisation promoting the interests

and associations involved in the supply, trading

such as storage and liquefied natural gas. EUROGAS wants to promote the smooth functioning of the

Traders and brokers

Contributions to this report were made by the members of three trade organisation

the trade organisations themselves: EFET, EURELECTRIC and EUROGAS.

The European Federation of Energy Traders (EFET) is a non-profit organisation designed to improve


liquid European wholesale market. EFET’s vision is “the achievement of sustainable energy markets



term benefit of the economy and of society”. EFET represents about 120 companies


fair share of EFET members are asset-backed traders like EDFT and RWE, but banks active in


EFET too. The major OTC brokers are all EFET members, also. There is no conflict between traders

oning OTC market is concerned, thus their responses could be bundled

The Union of the Electricity Industry (EURELECTRIC) is a sector-specific and non

association representing the common interests of the electricity industry at pan-European level.


direct members of EURELECTRIC are the national electricity associations, e.g. Österreichs E

Wirtschaft for Austria, FEBEG for Belgium, and BDEW for Germany. In countries where such



but also of generators and medium to small traders / distributors like the

profit organisation promoting the interests of companies, national federations

and associations involved in the supply, trading, and distribution of natural gas and related activities


27

organisations, and the staff of

profit organisation designed to improve


sion is “the achievement of sustainable energy markets



term benefit of the economy and of society”. EFET represents about 120 companies


EDFT and RWE, but banks active in


. There is no conflict between traders

oning OTC market is concerned, thus their responses could be bundled

specific and non-profit umbrella

European level.


direct members of EURELECTRIC are the national electricity associations, e.g. Österreichs E-

BDEW for Germany. In countries where such an



but also of generators and medium to small traders / distributors like the

companies, national federations,

n of natural gas and related activities


28

European internal gas market and to take a stance on issues of interest to the European natural gas

industry, primarily with respect to organisations on the European Union level. EUROGAS represents

50 members from 27 countries in the gas industry. Out of these 50 members, 33 are natural gas

companies, 15 are federations of natural gas companies, and two are international organisations.

Energy traders and brokers describe themselves as aware of upcoming reporting requirements in

general, with details and clarity in major areas missing for many market participants. Whilst all

traders and brokers realize that the reporting requirements are unavoidable and many think that at

least parts of the regulation are in general for the good of the market, there is a growing concern that

the pendulum is swinging from under-regulation rapidly into over-regulation. Even the largest market

participants with major financial resources and IT staff in the thousands are concerned about the

ability of their smaller counterparties to follow suit with obligatory regulatory demands. Should

market liquidity be substantially reduced by the market exit of these small traders and counterparties,

adverse effects to price stability and security of supply could result.

There is strong preference for clear and unambiguous rules, published in a timely fashion. Of course,

reporting requirements which can be fulfilled by moderate investments are preferred, but if that goal

cannot be reached, at least a clear path for future investments needs to be shown, especially in

conjunction with other regulatory regimes. Otherwise, uncertainty about direction and future needs

may start to paralyze the ability of large organisations to change according to the demands of the

markets, not just the anticipated future input from several regulators. A large share of the IT budget

for the fiscal year 2013 will need to be set aside for regulatory concerns. Timely input is of the essence.

Market participants have a high commitment to fulfil their reporting requirements, thus keeping their

core business legal. Some traders, especially traders more focussed on one market only, are looking to

establish third party reporting via energy exchanges and matching platforms. Their main concern is

the ability of those service providers to establish the legal and technical framework for this in time. A

clear signal from ACER about the timing and cooperation with such service providers would be most

welcome. Otherwise, all market participants will have to develop a plan B in case their data service

provider of choice does not meet a deadline or fails certification. Given the timeline of developing

major interfaces to their core production systems in trading, having a viable plan B means building an

own interface from the start. If this is done, it might as well be used, thus leading to thousands of

direct reporting parties vis-à-vis ACER. This can be neither in the interest of ACER nor in that of the

reporting parties.

Other traders, especially traders focussed on many market and market venues and thus under a

multitude of reporting regimes, are looking to take transaction reporting into their own hands by

establishing a group wide Regulatory Compliance function which fulfils that need with relation to all

regulatory bodies. Their main concern is not so much their own technical abilities, as they have more

control of it than of outside events, but the legal and process framework provided by ACER, such that

their envisioned architecture can work.

The OTC market is inherently more difficult to oversee than the exchange market. Apart from

exchange fees and lack of liquidity, there are good reasons that many transactions are done OTC: they

are complex and do not fit simple forms which would lend themselves to standard reporting as in the

financial markets. Data aggregators play a pivotal role in providing data for OTC wholesale energy

markets. Building upon existing energy trade data schemes in the OTC world contributes to an

efficient reporting framework under REMIT. Therefore, the focus of our recommendation is on the

data sets already available at the level of data aggregators, even though it will be reported directly by

some market participants.

29

Topic Content

Trade data All data that is derived from trading at energy exchanges is available

(orders and trades with corresponding information like time, volume,

price, etc.)

Realistically, orders to trade in OTC would only be available at broker

platforms.

If trading does take place without brokers and off automatic

confirmation sites, the aggregation of data would only be possible

directly from all participants

Transparency

platforms

Traders see themselves rather as consumers of fundamental data

published on transparency platforms

Interdependencies Overlap with MiFID/ MAD

Impact of MiFID II/ MiFIR

Different requirements in the financial markets according to MiFID and

the spot markets (Art. 15 of REMIT)

3.4.3. Exchanges

The Association of European Energy Exchanges (EUROPEX) is a not-for-profit association

representing the interests of the exchange-based wholesale markets for electrical energy and gas

with regard to developments of the European regulatory framework for wholesale energy trading.

EUROPEX currently has 17 European energy exchanges as members. Energy exchanges differ by

their status as profit or non-profit organisations, their mandatory or non-mandatory legal

framework, the national legal regime in place, as well as by the given economic conditions.

Energy exchanges describe themselves as both well suited and highly committed to helping market

participants to fulfil their reporting requirements. EUROPEX highlights the necessity of establishing

a clear legal framework for third party reporting; energy exchanges will also have to develop a

comprehensive business model that enables refunding the initial investment and the running costs.

Energy exchanges play a pivotal role in providing data for wholesale energy markets. Building upon

existing energy trade data reporting schemes contributes to an efficient reporting framework under

REMIT.

Topic Content

Trade data All data that is derived from trading at energy exchanges is available

(orders and trades with corresponding information like time, volume,

price, etc.)

Collection of orders to trade is a serious challenge to the overall process

(estimated 20-50 times more than trades)

Market surveillance Specific market surveillance reporting is done by exchanges to their

supervisory bodies

Various overlapping reporting obligations with REMIT in EU member

30

states

Need for central data repository to analyze cross-border market

behaviour is confirmed

Mechanisms established on a voluntary or mandatory basis – depending

on legal and regulatory framework

Explicit market surveillance office do not necessarily exist

NRA reporting In general, suspicious behaviour currently has to be reported to NRAs or

other exchange supervisory authorities already

Not all energy exchanges fall under MIFID/EMIR reporting obligations.

Certain exchanges are only active in spot markets (and not derivatives

markets) and are operating under different regulatory regimes

Transparency

platforms

Some but not all energy exchanges are involved in collection of

fundamental data

Interdependencies Interim period where MiFID/ MAD apply to a narrower set of

companies than what is expected after the entry into force of MiFID II/

MiFIR and CSMAD/ MAR; that narrower set, however, seems to fall

under REMIT

Different requirements in the financial markets according to MiFID and

the spot markets (Art. 15 of REMIT)

MiFID does not govern orders to trade

Availability of trade data is derived from trading at energy exchanges (including orders and trades

with corresponding information such as time, volume, price, etc.). According to EUROPEX, the

collection of orders to trade is a serious challenge to overall process since the number of such data

records is estimated at 20-50 times more than data for executed transactions.

For market surveillance, specific reporting is done by exchanges to supervisory bodies in their

respective countries. Such mechanisms are established on a voluntary or mandatory basis, and

therefore there may not be an explicit ‘market surveillance’ team in existence within each of the

exchanges' organisations. This depends on the country-specific legal and regulatory framework. In

this context, EUROPEX confirms a need for a central data repository to analyse cross-border trading

activity in line with the rationale identified for the introduction of REMIT.

For regulatory reporting, EUROPEX identified an existing rule that suspicious trading behaviour must

be reported to NRAs or other exchange supervisory authorities. With this in mind, it was mentioned

that at present not all energy exchanges fall under MIFID/EMIR reporting obligations, since certain

exchanges are only active in spot markets (and not derivatives markets).

Through participation in transparency platforms, some but not all energy exchanges are involved in

collection of fundamental data.

EUROPEX identified the main interdependencies with other ongoing regulatory workstreams as

occurring within an interim period where MiFID/ MAD apply to a narrower set of companies than

that which is expected after the entry into force of the revised forms of these regulations (i.e. MiFIR

and MAR). Under MIFIR and MAR certain exemptions may be removed which will mean that more

companies must comply. Some of these companies may already be within the scope of REMIT;

however they will only face double-reporting issues after the introduction of MiFIR/ MAR. EUROPEX

31

specifically pointed out that there are different requirements in the financial markets according to

MiFID and the spot markets (Art. 15 of REMIT) and that MiFID does not govern orders to trade.

3.4.4. NRAs

3.4.4.1. Introduction - involvement of NRAs via CEER

The National Regulatory Authorities are involved in this project via the Council of European Energy

Regulators (CEER). CEER is a Belgian not-for-profit organisation, set up by the National Regulatory

Authorities that serves as their voice on an EU and international level. This project has been presented

and discussed in the Market Integrity and Transparency Working Group of CEER, led by Mr. J. Braz

as chairperson. The project’s approach and scope was been presented on the 27th of February 2012 at

the CEER premises in Brussels in connection with a working group meeting. As listed in chapter 2.2

(“Project approach and methodology”) the workshop took place on the 28th of March 2012.

3.4.4.2. Fragmentation of supervision in the wholesaleenergy market

The collection of data with the purpose of monitoring transactions in the wholesale energy market is

currently fragmented. Energy market monitoring practices are member state and sector specific.29

Outside the applicability of MiFID, rules may exist at the member state level, however limited in

scope, often relating only to a single trading platform and covering a single member state.30

Different monitoring schemes by NRAs are already in action regarding the wholesale energy market.

In Germany for example, the Federal Grid Agency (Bundesnetzagentur – BNetzA) exercises its

regulatory tasks by monitoring the structure of the wholesale energy markets in particular (including

requests for data from broker platforms), whereas the European Energy Exchange in Leipzig is

supervised by the Saxon State Ministry of Economic Affairs, Labour and Transport (SMWA) as the

exchange supervisory authority under the German Exchange Act.31 As far as the supervision of trading

in financial instruments such as exchanged traded commodity derivatives is concerned, the Federal

Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht – BaFin) is

the competent body who is supported by the market supervisory offices at the stock exchanges.

In Austria, E-Control conducts monitoring in the area of electricity and gas by regularly monitoring

and evaluating the daily and weekly price developments at wholesale energy markets. For this, energy

market data providers are used. The energy trading venues Energy Exchange Austria (EXAA) and

Central European Gas Hub (CEGH) are supervised by the Austrian Financial Market Authority

(financial market) and by the Austrian Federal Ministry for Economic Affairs (spot market) under the

Austrian Exchange Act.32

In France the Commission de Régulation de l’Énergie has been entrusted with the task of monitoring

the French wholesale electricity and natural gas markets since 7th December 2006. CRE monitors

electricity and natural gas transactions between suppliers, traders, and producers; transactions

carried out on organised markets; and cross-border trades.33 At the European Power Exchange (EPEX

29 Recital 6 REMIT.30 Commission of the European Communities, Impact Assessment regarding REMIT of 8.12.2010, p. 13.31 Council of European Energy Regulators, Pilot Project for an Energy Trade Data Reporting Scheme, Final Report p. 1232 Council of European Energy Regulators, Pilot Project for an Energy Trade Data Reporting Scheme, Final Report p. 1333 Council of European Energy Regulators, Pilot Project for an Energy Trade Data Reporting Scheme, Final Report p. 13

32

SPOT), its market surveillance department has built up relations with EEX market surveillance on

power markets and with the supervisory authorities and energy regulators in charge of monitoring

EPEX SPOT markets as shown in the diagram below:34

Figure 5 EPEX Spot Market Surveillance Office – overview

However, even if differentiated trading supervisory mechanisms in place in single Europeanjurisdictions, there is no obligation for transaction reporting at the European level.35

3.4.4.3. Non-binding statements from the workshop with theNRAs

The formal views of the NRAs regarding the responses to the questionnaire are outlined in the

following chapter. However, in the following we have listed a number of general and comprehensive

thoughts on the framework for reporting under REMIT, which have been expressed in the NRAs’

workshop.

Withholding of capacity with the intention of manipulating the market belongs to theactivities which should be prevented and detected.

When setting up a reporting scheme the cost/benefit ratio should always be taken intoaccount (“No data collection for the sake of data collection”).

Especially in the gas market, it is necessary to encompass contracts already concluded inaddition to newly concluded contracts, since the existing long term contracts have a highrelevance in the market.

The focus of the reporting obligation should, in practice, lie on market exchanges and brokersrather than on individual market participants.

While real time reporting permits an intervention before it gets really problematic, reportingon a daily basis might be more cost efficient.

34 www.epexspot.com/en/market_surveillance.35 Council of European Energy Regulators, Pilot Project for an Energy Trade Data Reporting Scheme, Final Report p. 15.

33

While trade data should be available on a daily basis, fundamental data could be, underspecified circumstances, reported less frequently.

The immediate access to fundamental data on unplanned outages should have a high priority.

General awareness regarding the tension between the need for standardization versus theneed for providing detailed information.

Regarding access to the ACER database for the public and for scientific purposes, a pragmaticapproach should be followed. The sensitivity of the market participants for older data mightbe much lower.

3.5. Electricity TSOs

3.5.1. Introduction

Electricity transport system operators (TSOs) constitute the cardinal focus points for the data

provision in the wholesale energy market. The necessity of a sophisticated allocation of capacities for

electricity units deemed to be transported in the internal market, including between the grids of

various TSOs, puts electricity TSOs in the position of having to collect and exchange data on times and

volumes. In addition, TSOs are faced with a series of reporting requirements laid out in legal

provisions and guidelines.

The foremost legal provision for data reporting on a pan-European level is found in Chapter 5 of the

Guidelines on the Management and Allocation of Available Transfer Capacity of Interconnections

between National Systems, Annex I to Regulation (EC) No 714/2009 (Regulation of the European

Parliament and of the Council of 13 July 2009 on conditions for access to the network for cross-border

exchanges in electricity and repealing Regulation (EC) No 1228/2003). The addressees to the

reporting requirements under these guidelines include both TSOs and, in some instances, market

participants. Under chapter 5 of the guidelines, TSOs are obliged to publish certain pieces of

information and data sets, whereas national regulatory authorities (as defined in Article 35 (1) of

Directive 2009/72/EC) are given the power to review the manner in which such information is

published in some cases.

Other significant sources of information on data transparency are the European Regulators' Group for

Electricity and Gas (ERGEG) Advice on Comitology Guidelines on Fundamental Electricity Data

Transparency (Ref: E10-ENM-27-03, published on 7 December 2010) and the ENTSO-E

Transparency Platform run by the European Network of Transmission System Operators for

Electricity (ENTSO-E).

Additionally, ENTSO-E has contributed a summary of the responses submitted by electricity TSOs to

the questionnaire sent out by PwC and Ponton in order to understand the stakeholders view on

reporting requirements.

Eventually, national regulatory frameworks on reporting obligations can indicate which type of data

and manner of reporting could easily be integrated in the REMIT data reporting framework. However,

no thorough analysis of all European jurisdictions has been undertaken for the purposes of this report.

Rather, information on national regulation as contributed by means of the ENTSO-E summary of the

responses to the questionnaire and the German national regulatory framework have been taken into

account.

34

3.5.2. Data currently reported and/or published by electricityTSOs on an individual basis (fundamentaldata/transparency provisions)

According to Articles 15 and 16 of Regulation (EC) No 714/2009 and as set forth in Chapter 5 of the

Guidelines on the Management and Allocation of Available Transfer Capacity of Interconnections

between National Systems, electricity TSOs are obliged to publish information on

a) network availability, access and use, including comprehensive multi-faceted congestion

reports and capacity allocation procedures (1. to 3. below);

b) operational and planning security standards (4. below);

c) cross-border trade based on the best possible forecast (5. (a) to 5. (i) below).

The data sets described in a) to c) above shall be considered fundamental data according to the

definition laid out in section 1.1 of the ERGEG Advice on Comitology Guidelines on Fundamental

Electricity Data Transparency.

Currently, electricity TSOs are required to publish the information on an individual basis and are

fulfilling their transparency requirements by publishing fundamental data on their respective

websites.

When TSOs and market participants, as the case may be, publish the aforementioned pieces of

information, certain timeframes need to be considered (7. below). As far as forecasts shall be

published, ex-post realized values shall also be published at the latest on the following day ("D+1").

In order to comply with the programmatic background of Chapter 5 ("transparency"), all information

must be published in a manner that it remains freely available in an easily accessible form (8. and 9.

below). In order to nurture the harmonisation within the internal market, TSOs shall exchange

sufficiently accurate network and load flow data (10. below).

In detail, the guidelines put these requirements forward as follows:

1. TSOs shall publish all relevant data related to network availability, network access, and

network use, including a report on where and why congestion exists, the methods applied

for managing the congestion, and the plans for its future management.

2. TSOs shall publish a general description of the congestion-management method applied

under different circumstances for maximising the capacity available to the market, and a

general scheme for the calculation of the interconnection capacity for the different

timeframes, based upon the electrical and physical realities of the network. Such a scheme

shall be subject to review by the regulatory authorities of the member states concerned.

3. The congestion management and capacity allocation procedures in use, together with the

times and procedures for applying for capacity, a description of the products offered, and

the obligations and rights of both the TSOs and the party obtaining the capacity, including

the liabilities that accrue upon failure to honour obligations, shall be described in detail and

made available in a transparent manner to all potential network users by TSOs.

4. The operational and planning security standards shall form an integral part of the

information that TSOs publish in an open and public document. That document shall also be

subject to the review of the national regulatory authorities.

5. TSOs shall publish all relevant data concerning cross-border trade on the basis of the best

possible forecast. In order to fulfil that obligation, the market participants concerned shall

35

provide the TSOs with the relevant data. The manner in which such information is published

shall be subject to review by the regulatory authorities. TSOs shall publish at least:

(a) annually: information on the long-term evolution of the transmission infrastructure and

its impact on cross-border transmission capacity;

(b) monthly: month- and year-ahead forecasts of the transmission capacity available to the

market, taking into account all relevant information available to the TSO at the time of

the forecast calculation (for example, impact of summer and winter seasons on the

capacity of lines, maintenance of the network, availability of production units, etc.);

(c) weekly: week-ahead forecasts of the transmission capacity available to the market,

taking into account all relevant information available to the TSOs at the time of

calculation of the forecast, such as the weather forecast, planned network maintenance

work, availability of production units, etc.;

(d) daily: day-ahead and intra-day transmission capacity available to the market for each

market time unit, taking into account all netted day-ahead nominations, day-ahead

production schedules, demand forecasts, and planned network maintenance work;

(e) total capacity already allocated, by market time unit, and all relevant conditions under

which that capacity may be used (for example, auction clearing price, obligations on

how to use the capacity, etc.), so as to identify any remaining capacity;

(f) allocated capacity as soon as possible after each allocation, as well as an indication of

prices paid;

(g) total capacity used, by market time unit, immediately after nomination;

(h) as closely as possible to real time: aggregated realised commercial and physical flows,

by market time unit, including a description of the effects of any corrective actions taken

by the TSOs (such as curtailment) for solving network or system problems;

(i) ex-ante information on planned outages and ex-post information for the previous day

on planned and unplanned outages of generation units larger than 100 MW.

6. All relevant information shall be available for the market in due time for the negotiation of

all transactions (such as the time of negotiation of annual supply contracts for industrial

customers or the time when bids have to be sent into organised markets).

7. The TSO shall publish the relevant information on forecast demand and on generation

according to the timeframes referred to in points 5 and 6. The TSO shall also publish the

relevant information necessary for the cross-border balancing market.

8. When forecasts are published, the ex post realised values for the forecast information shall

also be published in the time period following that to which the forecast applies or at the

latest on the following day (D + 1).

9. All information published by the TSOs shall be made freely available in an easily accessible

form. All data shall also be accessible through adequate and standardised means of

information exchange, to be defined in close cooperation with market participants. The data

shall include information on past time periods with a minimum of two years, so that new

market entrants may also have access to such data.

10. TSOs shall exchange regularly a set of sufficiently accurate network and load flow data in

order to enable load flow calculations for each TSO in their relevant area. The same set of

data shall be made available to the regulatory authorities and to the Commission upon

36

request. The regulatory authorities and the Commission shall ensure the confidential

treatment of that set of data, by themselves and by any consultant carrying out analytical

work for them on the basis of those data.

The table below summarises the data that is required to be published under Regulation (EC)

714/2009 as quoted above:

Table 2 Data to be published under Regulation (EC) 714/2009

Data item Timeframe Due date

Network availability, access, use In due time for the negotiation

of all transactions

Congestion report (existence of and

reason for congestions,

management methods, and future

management plan)

In due time for the negotiation

of all transactions

Congestion management method

and interconnection capacity

For the different timeframes In due time for the negotiation

of all transactions

Congestion management and

capacity-allocation procedures in

use, together with the times and

procedures for applying for capacity


of all transactions

Description of the products offered,

including rights, obligations, and

liabilities


of all transactions

Operational and security planning As an integral part of the

information otherwise

submitted

Information on the long-term

evolution of the transmission

infrastructure and its impact on

cross-border transmission capacity

Long-term Annually

Forecasts of the transmission

capacity available to the market

(e.g. considering impact of summer

and winter seasons, maintenance,

availability of production units,

etc.)

Month- and year-ahead Monthly

Forecasts of the transmission

capacity available to the market,

(e.g. considering the weather

forecast, planned network

maintenance work, availability of

production units, etc.)

Week-ahead Weekly

Transmission capacity available to

the market taking into account all

Day-ahead

Intra-day for each market

Daily

37

netted day-ahead nominations,

day-ahead production schedules,

demand forecasts, and planned

network maintenance work

time unit

Total capacity already allocated and

all relevant conditions under which

that capacity may be used (for

example, auction clearing price,

obligations on how to use the

capacity, etc.), so as to identify any

remaining capacity

By market time unit In due time for the negotiation

of all transactions

Allocated capacity as well as an

indication of prices paid

As soon as possible after each

allocation

Total capacity used By market time unit Immediately after nomination

Aggregated realised commercial

and physical flows including a

description of the effects of any

corrective actions taken by the

TSOs (such as curtailment) for

solving network or system

problems

By market time unit As close as possible to real

time

Ex-ante information on planned

outages and ex-post information for

the previous day on planned and

unplanned outages of generation

units larger than 100 MW.

a) Future

b) Previous day

a) In due time for the

negotiation of all transactions

b) D+1

TSOs also report fundamental data on a national level. These national reporting

requirements are to be seen as cumulative to the reporting requirements on a European level and add

hourly data reporting to the daily, weekly, or long-term data reports according to Regulation (EC)

714/2009. According to the ENTSO-E summary of TSO responses to the questionnaire, fundamental

data reported on a national level may include the following data sets (shown by the example of

Norway as published at http://www.npspot.no):

Hourly data per bidding area

a) Day ahead auction capacities (for cross-border trade);

b) Intraday market capacities (for cross-border trade);

c) Balancing market capacities (for the common Nordic market);

d) Production per bidding area;

e) Consumption per bidding area;

f) Net exchange per bidding area;

g) Reservoir filling.

38

Under German national law, fundamental data which has to be published by electricity TSOs without

undue delay and held accessible for a minimum duration of two years (e.g. on a website) comprise the

following data sets as laid out by section 17, paragraph 1 of the Electricity Grid Access Ordinance

(Stromnetzzugangsverordnung or StromNZV). These requirements were put in place on a national

level before Regulation (EC) 714/2009 was put into force. However, requirements under section 17

StromNZV are not in conflict with the Regulation, but rather complement these by hourly or quarter-

hourly data.

a) Aggregated load submitted to Distribution System Operators (DSO) or consumers (vertical

load) per hour and per MWh;

b) Annual maximum load and the load curve measured on a quarter-hourly basis;

c) Net losses;

d) Quarter-hourly control area balance per MWh per quarter hour as well as the activated

reserve per minute;

e) Cross-border flows aggregated per coupling point, including a forecast on the capacity

allocation;

f) Market-relevant outages and planned revisions;

g) Volumes and prices of lost energy (grid losses);

h) Data on scheduled feed-in of wind energy on the basis of forecasts as used by TSOs and on the

basis of actual feed-in on the basis of the data TSOs use among each other (per MWh per

hour).

Thus, under the national regimes depicted above, hourly or even quarter-hourly fundamental data is

available complementing the data to be published and/or reported in accordance with Regulation No.

714/2009 (see table above).

3.5.3. Data readily available (transactional data)

According to the ENTSO-E summary of TSO responses to the questionnaire, data sets as laid out in

the following paragraphs are available.

Commercial data items which can be extracted from long-term capacity contracts:

a) Transmission capacity or generation capacity, offered capacity, allocation results;

b) Interconnection, business interval, monthly and yearly market data, pricing method (uniform

price);

c) Time horizon, PTR (physical transmission right) volumes, commercial profile areas, BRPs

(balance responsible parties), prices.

However, there are no long-term capacity contracts in the Nordic market area, UK, Ireland, or Greece,

disregarding possible bilateral contracts to non-EU parties (e.g. Russia).

Data available from capacity auctions comprise:

a) Offered capacity;

b) Requested capacity;

c) Allocated capacity;

d) Price capacity;

39

e) Bid curve;

f) Bilateral transfers and resales;

g) Interconnector data.

These data are made available in harmonised XML documents as documented on the ENTSO-E EDI

library (https://www.entsoe.eu/resources/edi-library/).

Data available from the balancing energy market comprise:

a) Bilateral and power exchange transactions (day ahead and intraday);

b) Prices (bids and offers);

c) Volumes of primary, secondary, and tertiary reserves;

d) Volumes of settled balancing energy;

e) Balancing energy offers (available generating capacity and offered prices);

f) Bidding area;

g) Location.

It has to be considered that in some states such as Ireland or Greece, no balancing energy markets

exist, since there is a pool system under which a plant is centrally dispatched to balance supply and

demand. Therefore, data available from these regions (Ireland, Greece) merely refer to imbalance

settlements which are dealt with by collecting data on unit availabilities and imbalance prices per

MW, respectively.

Trade data collected on a national level may comprise (shown by the example of Norway as

published at http://www.npspot.no and http://www.statnett.no using the ENTSO-E XML format

schemes):

Hourly data per bidding area:

a) Day ahead auction prices, volumes, and cross-border flows;

b) Intraday market prices, volumes, and cross-border flows;

c) Balancing market prices (tertiary reserve, prices also used for imbalances) and volumes;

d) Special regulation volumes (tertiary reserve out of merit order);

e) Automatic reserves (primary) activated volumes;

f) Automatic reserves (primary) reserved capacities;

g) Automatic reserves (primary) capacity prices.

In Germany, the NRA has instituted the "Market Rules for the Performance of Balancing Group

Accounting in Electricity" ("MaBiS"). These rules address the TSOs in their role as balancing group

supervisors. The balancing group supervisor is responsible for making sure that the power balance of

the balancing group is in equilibrium in each 15-minute measuring period. Under these rules,

electricity TSOs are obliged to communicate detailed trade data among the market participants on a

monthly basis, whereas the data sets have to refer to the respective energy trade volume in kWh and

are based on quarter-hourly feed-ins.

The procedure and formats are not yet standardised, therefore each of the four German electricity

TSOs has implemented its own procedures which apply until the NRA (or another responsible

40

authority) issues a standard process and format. For example, TenneT TSO GmbH uses the MSCONS

data format.

Per balance region, the TSO determines the balance totals per balance area for the following types of

time series:

Load curve total (LCT) per balance area (incl. associated (proprietary) sales);

Feed-in curve total (FCT) = total time series feed-in curve time series of feed-in points

per balance area. Power from renewable energy is fed-in, thus the feed-in curve total

must also be transmitted for renewable energy systems read (separated by energy

source);

Standard feed-in profile total (SET) = Total time series synthetic feed-in profiles per

balance area. Power from renewable energy is fed-in, thus the feed-in curve total must

also be transmitted for renewable energy systems not read (separated by energy source);

Standard load profiles (SLP) synthetic or analytical;

Daily parameter-dependent load profile total (DLT) per balance area;

Daily parameter-dependent feed-in profile total (DET) per balance area;

Aligned grid time series (GTS) - the difference between the totals of all grid time series -

must be transmitted for subordinate or neighbouring grids.

The invoices according to the balancing group contract, according to the monthly totals, usually

comprise the following information:

Work: MWh including 6 decimal places;

Separation of ‘000s for quantities and monetary amounts;

Identification of excess quantities of the balancing group by adding the term “excess”;

Identification of shortfalls of the balancing group by adding the term “shortfall”;

Monetary amounts in the legal currency: EUR (€);

Disclosure of the shortfall quantities (MWh) and of the monetary amount (net) for

shortfalls;

Disclosure of the excess quantities (MWh) and of the monetary amount (net) for excess;

Disclosure of the balance of the shortfall quantities minus excess quantities (MWh);

Disclosure of the monetary amounts (net) for shortfall and excess quantities as well as of

the sum of these two monetary amounts (net), broken down according to tax rates, if

required, insofar and for as long as this is possible according to the legal provisions, in

particular, those of VAT laws and their interpretation by the state financial authority

competent for each TSO (in their role as balancing group coordinator, or "BIKO"); if such

a disclosure is not permitted according to such laws, the presentation is made according

to the legal requirements and, in particular, according to the requirements of the VAT

laws as well as the interpretation by the state financial authorities mentioned above;

Disclosure of the VAT rate and disclosure of the VAT amount applicable to the tariff (net

monetary amount);

Disclosure of the gross total;

Date of maturity / value date of invoice.

41

The time at which data on the final allocated volume is confirmed varies depending on the TSO at

stake and the type of volume addressed (transmission capacity or volume). ENTSO-E summarises

from the answers to the questionnaire that balancing power allocation volumes might be confirmed at

two hours after the final allocation (H+2), whereas cross-border trade allocations might be confirmed

at H-1 in some cases (e.g. the British market, with a half-hourly reporting scheme) and H+1 in others

(e.g. SvK, Statnet, REN). However, with EirGrid (Ireland), timeframes generally are D+4 for

generation and interconnectors and M+13 for suppliers and non-price-affecting generation.

When obliged to report data whose primary owner are generators, TSOs depend on the thresholds

generators consider when reporting their data. According to the responses to the questionnaire,

generators mostly report data exceeding 100 MW (e.g. publication of planned and unplanned outage),

however there are exceptions to that threshold. Installed generation capacity might be reported with a

1 MW threshold or, for solar and wind energy, even with 0.1 MW. Also, there are regional differences

(e.g. the standard reporting threshold for England and Wales is 100 MW, for South Scotland 30 MW,

and for Northern Scotland 10 MW).

With the opening of the European internal energy market, definitions of standardised information

interchange interfaces (data formats) were necessary. Since 2000, ETSO and now ENTSO-E have

been providing the electricity market with recommendations and implementation guides for various

business processes such as Scheduling System (ESS), Settlement and Reconciliation (ESP),

Transmission Capacity Allocation and Nomination (ECAN), Reserve Resource Process (ERRP), etc.

ENTSO-E reports that this harmonisation work is being accomplished by the International

Electrotechnical Commission (IEC) and in particular through the Technical Committee (TC) 57 WG 16

on “Deregulated Energy Market Communications”, to which ENTSO-E contributes expertise and

recommendations. Core components have been defined by ENTSO-E (including their mapping with

CIM classes) and are currently used in exchanges for the electricity market as well as for the

publication of information on the entsoe.net platform. All the documentation related to these

harmonised XML documents is found on the ENTSO-E EDI library at

https://www.entsoe.eu/resources/edi-library/. The ENTSO-E WG EDI has furthermore developed the

"Market Data Exchange Standard", i.e. MADES, in order to ensure a single face to the market and to

provide encryption, secrecy, and authentication and at the same time guarantee information

transmission. The MADES standard is found at

https://www.entsoe.eu/fileadmin/user_upload/edi/library/mades/mades-v1r0.pdf

As regards capacity bookings, electricity TSOs and the regional capacity auction offices (e.g. CAO

Central Allocation Office GmbH) currently do not use a standardised format. However,

communication and confirmation report messages are communicated by most TSOs/ regional

capacity auction offices in the XML schema on which the ESS version 3.3 or ECAN 4.0 format is

based. In several cases, the usage of the ESS or ECAN version is written down in balancing group

contracts (Bilanzkreisvertrag), e.g. the Balancing Group Contract of TenneT TSO GmbH (28th of July

2011).

3.5.4. Harmonised fundamental data (ENTSO-E transparencyplatform)

ENTSO-E has established a transparency platform which is operational since 2007 at www.entsoe.net.

It publishes many data items of great interest to electricity traders on a daily basis. It contains key

operational and congestion management information for Europe's high voltage electricity

transmission interconnectors.

42

The data submitted to the ENTSO-E transparency platform by electricity TSOs on a voluntary basis

comprise:

a) Vertical load;

b) Physical flows;

c) Auction data;

d) Commercial schedules;

e) Net transfer capacities;

f) Outage;

g) Balancing.

Data submission to the ENTSO-E transparency platform is completed by a large number of, but not

all, electricity TSOs and also by power exchanges, auction offices, and further third parties. The data

submitted to the platform is used by traders, consultants, the European Commission, ACER, by the

media, universities, and by individuals.

At the transparency platform, each TSO has a single point of contact (TPC = Transparency Platform

Coordinator). Data is submitted via ftp, e-mail, or entered directly. Data submission standards are

being developed by the EDI WG (see above).

3.5.5. Summary on REMIT data currently available

The following table outlines the REMIT data currently available, structured by fundamental data

(mandatory requirements and voluntary platform) and transactional data (trade and transport

contract data).

Table 3 REMIT data currently available

Fundamental data

(transparency

requirements)

• Currently published by TSOs (as required by Chapter 5 of Annex

I to Regulation No. 714/2009

• Data include network availability, network access, network use,

congestion management, capacity allocation, liabilities,

operational and planning security standards, planned and

unplanned outages, forecasts, and ex-post realised values

• Requirements to be fulfilled on an individual TSO basis

Fundamental data –

ENTSO-E Transparency

Platform

• Platform collecting transparency data for TSOs and further

market participants

• Currently operating on a voluntary basis

• Data includes vertical load, physical flows, auction data,

commercial schedules, net transfer capacities, outage, balancing

• Data submission via ftp, e-mail, or direct entry

• Data format standard development under way by ENTSO-E WG

EDI

43

Trade/ transportation

contract data (capacity

allocations/scheduling;

balancing)

• TSOs hold data on capacity allocations and scheduling

• Various data formats used for capacity allocation

• ESS used for scheduling Europe-wide by many TSOs

• Balancing market systems differ by region/country

• Limited reporting to NRAs

3.5.6. ERGEG Advice on Comitology Guidelines onFundamental Electricity Data Transparency: Data items tobe published according to the ERGEG draft

According to the ERGEG Advice on Comitology Guidelines on Fundamental Electricity

Data Transparency, the respective market participants shall collect and contribute data to the

future central information platform on:

a) Load (data provider: TSOs; third party contributions to data provider: generation and

consumption units and the DSOs within the respective TSO's control area);

b) Transmission and interconnectors (data providers: TSOs, transmission capacity allocators);

c) Generation (data provider: generators);

d) Balancing (data providers: TSOs or operators of balancing markets, as the case may be).

Such data shall be made available and disclosed in the following manner:

a) Without undue delay and according to the timing requirements defined;

b) On a common European website provided by ENTSO-E;

c) The website is to be easily accessible to the public, free of charge for the information specified

in these guidelines; however, a neutral point of contact has to be provided;

d) Update on a regular/rolling basis; the update frequency shall be according to the changes that

take place;

e) Information shall be stored for at least 5 years in the central information platform;

f) In a user-friendly manner, in downloadable format that allows for quantitative analyses;

g) In consistent units as required by these guidelines; and

h) In English.

The minimum contents of the data sets which TSOs are responsible to provide as set forth in the

ERGEG Advice on Comitology Guidelines on Fundamental Electricity Data Transparency are

summarised in the tables below.

44

Table 4 TSO Data requirements - Load

Data item a) Timeframe

b) Unit

Due date Primary data

owners

Load

Actual total load a) Hourly

b) -

At the latest one hour

after the operational

hour (H+1)

TSOs

Owners of

generation units

Estimate of the total

load

a) Day-ahead

b) Market time unit per

bidding area

On the day before the

operational day at the

latest one hour before

the gate closure time of

the day-ahead market

in the bidding area.

To be updated, if

necessary.

TSOs

DSOs

If weekly energy and

capacity products are

offered: Estimate of the

total load per bidding

area per day, for every

day of the coming week

a) Week-ahead

b) Per bidding area per

day for every day of the

coming week: W

maximum, minimum

and average load values

(21 individual data)

Each Friday at the latest

one hour before the

gate closure time of the

day-ahead market in

the bidding area.

To be updated, if

necessary.

TSOs

DSOs

If monthly energy and


offered, an

estimate of the total

load

a) Month-ahead

b) Per bidding area;

for each week

maximum, minimum


One week before the

monthly capacity

auction, or at the latest

one week before the

delivery month

TSOs

DSOs

If yearly energy and


offered, an

estimate of the total

load

a) Year-ahead; for the

following year


for each month

maximum, minimum


One week before the

yearly capacity auction,

or at the latest one week

before the delivery

year

TSOs

DSOs

A forecast margin,

which is defined as the

difference between

yearly forecast of

available generation

capacity and yearly

a) Year-ahead

b) Per bidding area,

(MW) evaluated at local

market time unit of

annual maximum load

One week before the

yearly capacity auction

or at the latest one week

before the delivery year

Total load forecast:

TSOs, DSOs

Available

generation

capacity: Owners of

45


b) Unit


owners

forecast of total load.

Information on

generation capacity

shall include forecast of

total generation

capacity, forecast of

availability of

generation and forecast

of reserves contracted

for system services.

generation units

Ex-ante information on

the planned

unavailability of

consumption units. Any

change in the

availability of a

consumption unit is

required to be reported

and published if the

change in available

capacity of the

consumption unit

equals to or exceeds 100

MW and lasts at least

one market time unit.

a) -

b) Name of the

consumption unit,

location, bidding area,

available capacity

during the event,

installed capacity,

reason for the

unavailability and start

and estimated stop date

(day, hour) of the

unavailability.

As soon as possible and

at the latest H+1 after

the decision is made.

To be updated with

changes as soon as

possible and at the

latest H+1 after the

decision.

Owner of the

consumption unit

that is subject to

planned

unavailability

Ex-post information on

the unplanned

unavailability of

consumption units. Any

change in availability of

a consumption unit is

required to be reported

and made public if the

unplanned change in

availability of the

consumption unit

equals or exceeds 100

MW and lasts for at

least one market time

unit.

a) -

b) Name of the

consumption unit,

location, bidding area,

available capacity

during the event,

installed capacity,

reason for the

unavailability and the

start and estimated stop

time (day, hour) of the

unavailability.



the outage or when an

update is available.

Owner of the

consumption unit

that is subject to

unavailability.

1. Transmission and interconnectors


b) Unit


owners

46


b) Unit


owners

Transmission and interconnectors

Information on expansion

and dismantling projects

in their national

transmission grids with

the estimated impact

(MW) also on the

interconnection capacity

(NTC) for minimum the

following three years.

This information must be

given for projects with a

relevant effect on transfer

capability (NTC) between

bidding areas. A relevant

effect is considered to be

an effect that equals or

exceeds 100 MW at least

during one market time

unit.

a) Annually, for the

minimum the following

three years


for every network

component and

interconnector project,

the TSOs shall make

public the name of the

assets concerned. Also,

the location, type of

asset, the impact on

interconnection

capacity between the

bidding areas, and the

estimated date of

completion shall be

provided.

The information shall

be published one week

before the yearly

transmission capacity

auction or at the latest

one week before the

delivery year.

Information is to be

updated with relevant

changes before end of

March, end of June

and end of September

of year Y.

TSO

Transmission and interconnection capacity

For explicit auctions, the

capacity offered by

TSOs, the capacity

requested by the market,

and the capacity allocated

to the market

a) Every market time

unit

b) MW;

price of the capacity;

congestion revenue per

border between

bidding areas.

At the latest H+2 after

each auction

TSOs

For explicit auctions, the

total capacity nominated

a) Every market time

unit

b) Between bidding

areas

At the latest H+2 after

each nomination

TSOs

For cross-border implicit

auctions, the allocation

results

a) -

b) Per market time

unit; MW; equal to net

positions of each

bidding area; price of

each bidding area

(Euro per MWh);

congestion income per

border between

- TSOs

47


b) Unit


owners

bidding areas.

Report on where and why

structural cross-border

congestion exists. This

report shall indicate where

the limiting constraint in

the transmission network

is located, to what extent

this constraint affects the

level of transmission

capacity (how many

hours/days/weeks/months

in the year) and all

possible corrective

measures that could be

implemented to increase

the transmission capacity,

together with their

estimated cost. The

methodology and projects

for achieving the long-

term solution shall be

described

a) Yearly;

b) At least on a regional

level

Updated during the

year where necessary

TSOs

Aggregated final

commercial scheduled

exchanges and physical

flows

a) -

b) By market time unit;

between bidding areas

As closely as possible

to real time and at the

latest H+2

TSOs or power

exchanges

Reasons and effects on net

transfer capacity (NTC) of

actions taken by TSOs and

having a significant

impact on NTC.

Information shall include a

description of the effects of

any corrective actions

taken by the TSOs (such as

curtailment, reduction of

grid feed-ins or withdrawal

and grid-related measures)

for solving network or

system problems.

a) -

b) equal to or above

100 MW during at least

one market time unit

Information on NTC

modification shall be

published at H+2 and a

complete report on

D+1

TSOs

Cross-border transfer

capacity

a) -

b) MW reserved as


be published at the

TSOs

48


b) Unit


owners

priority rights between

the EU and non-EU

member states per

product period

entry into force of

these guidelines and

updated as soon as

there is a modification

in the information.

If any type of Available Transmission Capacity (ATC) method is applied for capacity

calculation:

Planned outages on

interconnections between

bidding areas and in the

transmission grid that

reduce interconnection

capacity between bidding

areas, if the estimated

impact on capacity (NTC)

equals or exceeds 100 MW

during at least one market

time unit.

Information shall contain

the name of the asset

concerned, the place

(including affected bidding

area), the type of asset, the

start and estimated stop

dates of the outage (day,

hour), the estimated

impact (MW) on

transmission

capacity(NTC) between the

bidding areas and the

reasons.

a) start and estimated

stop dates of the outage

(day, hour);

b) MW

This information is to

be published at the

latest one week before

the yearly transmission

capacity auction, or if

no transmission

capacity auctions are

conducted, at the latest

one week before the

delivery year.


be updated with

changes at the latest

H+1 after information

is known

TSOs


actual outages (planned

and unplanned) in the

transmission grid and on

interconnections between

bidding areas if the impact

on transmission capacity

(NTC) equals or exceeds

100 MW during at least

one market time unit.

a) Start and estimated

stop dates (D, H) of the

actual outage

b) Asset concerned;

location; affected

bidding area; type of

asset; impact on



in MW



the occurrence

The reasons for the

outage should be

published at the latest

on the next day

TSOs

In the case of explicit


auctions, the offered

a) -

b) MW

Sufficiently in advance

of the auction;

TSOs

49


b) Unit


owners

capacity (MW) in the

explicit capacity auction

In view of year-ahead,

month-ahead, and

week-ahead auctions,

publication should be

done sufficiently in

advance and no later

than one week before

the auction

In the case of implicit

auctions, the offered day-

ahead capacity (MW)

a) -

b) MW

At the same time that

TSOs provide capacity

value to the entity

responsible for the

implicit auction

TSOs

Estimated net transfer

capacity (MW) for the next

day

a) For the next day

b) MW; for each border


and per direction; per

market time unit

Information shall be

published daily, at the

same time that the

offered day-ahead

capacity (MW) is

published

TSOs

If applicable (if weekly

energy and capacity

products are offered),

estimated net transfer

capacity (MW)

a) For the next week


between two bidding

areas and per direction;

one value per day


published Friday the

week before the

delivery week, at the

latest 1 hour before the

gate closure time of the

day-ahead market in

the bidding area

TSOs or

Transmission

Capacity Allocator

If applicable (if monthly

energy and capacity



capacity (MW)

a) For the next month



and per direction; one

value per week with

one maximum and one

minimum value per

market time unit


published at the latest

one week before

monthly transmission

capacity auction and at

18h00 at the latest

TSOs

If applicable (if yearly

energy and capacity



capacity (MW)

a) For the next year



and per direction; one

average value per

month

This information is to

be published at the

latest one week before

yearly transmission

capacity auction and at

the latest one week

before the delivery year

at 18h00 at the latest

TSOs

50


b) Unit


owners

For the intraday market

estimated hourly available


(MW)

a) For the next day

b) MW; between

bidding areas and per

direction; per market

time unit

At D-1, as soon as day-

ahead capacity is

known and at the latest

at 18h00.

Data should be

updated per market

time unit after each

change

TSOs

If applicable, for DC links,

information on any

restrictions placed on the

use of available cross-

border capacity through

the application of ramping

restrictions or intraday

transfer limits.

- - TSOs

In the case of flow-based allocation for the capacity

Non-redundant flow-based

parameters containing

power transfer

distribution. Factor

(PTDF) matrix with

physical margins (MW)

available for the

market/allocation

associated to the

anonymous critical

branches

a) Per day (D)

b) MW; per market

time unit

At D-1 before the

(implicit or explicit)

auction day for D

Transmission

Capacity Allocator

Flow-based allocated

capacity (MW) per non-

redundant critical

branches, in D-1

a) D

b) MW; per market

time unit

H+2 after auction

(implicit or explicit)

results have been

released

Transmission

Capacity Allocator

For intraday market, non-

redundant flow-based

parameters containing

PTDF matrix with

estimated physical

margins (MW) available

for the intraday allocation

associated to the

anonymous critical

branches

a) -

b) MW; per market

time unit

At D-1 after day-ahead

nominations/schedules

are known.

Data should be

updated per market

time unit after each

change

Transmission

Capacity Allocator

51

Table 5 TSO Data requirements - Balancing


b) Unit


owners

Balancing

Balancing and balancing market

If applicable, reserved

balancing reserves

either according to legal

requirements

or by procurement

processes, ex ante

a) -

b) Time unit for which

the reservation is made

(e.g. hour, day, week,

month, year, etc.)

To be published as soon

as possible, no later

than two hours before

the next procurement

process takes place

TSOs

If applicable, prices of

ex ante capacity

reservations paid to

generators or load

for each kind of reserve,

and the relevant pricing

methodology

a) -

b) Time unit for which

the payment is made

(e.g. hour, day, week,

month, year, etc.)

To be published as soon

as possible, no later

than two hours before

the next procurement

process takes place

TSOs

Ex-post aggregated

offers for activation to

the TSO separated for

each type of reserve

a) -

b) Market time unit

As soon as possible, no

later than two hours

after the operating hour

TSOs


the activated balancing

reserves

a) -

b) Balancing time unit

As soon as possible, at

the latest two hours


TSOs


actual prices (average

and marginal prices)

paid by TSOs for

balancing energy

To be published

sufficiently before the

following procurement

procedure

TSOs

Imbalance prices a) -

b) Per balancing time

unit

As soon as possible, at

least two hours after the

operating hour.

If there is an ex ante

procurement

procedure, the

information shall be

given at least two hours

before the following

procurement procedure

TSOs

Volumes of the

aggregated imbalances

and actually used

volumes of balancing

reserves inside control

a) -


unit

One hour after the

operating hour, the

information shall be

published one hour


TSOs

52


b) Unit


owners

areas

Financial balance of the

control area

a) Monthly

b) -

At the latest on the last

calendar day, three

months after the

operational month.

If settlement is

preliminary, the figures

shall be updated after

the final settlement

TSOs

Market information on

the type of balancing

bids/offers used

a) -

b) -

- TSOs

TSO-TSO cross border balancing exchanges

Volumes of exchanged

bids and offers

a) -


unit

After the operating

hour

TSOs

Maximum and

minimum prices of

exchanged bids and

offers

a) -


unit

After the operating

hour

TSOs

Volume of balancing

energy activated in

various control areas

within joint cross-

border balancing

a) -


unit

After the operating

hour

TSOs

3.6. Gas TSOs

3.6.1. Introduction

This section outlines the key existing channels for Gas Transmission System Operators (TSOs). In

particular, we provide an overview of:

Existing fundamental data currently published by Gas TSOs as required by Chapter 3 of

Annex I to Regulation (EC) no.715/2009;

Existing fundamental data currently published via the ENTSOG Transparency Platform;

Existing disaggregated trade data/fundamental data currently collected, but typically not

published by TSOs (including primary and secondary allocations, nomination and balancing

data).

53

3.6.2. Fundamental data published by gas TSOs on anindividual basis (transparency data)

For the purposes of this section, and without prejudice to further guidance provided by the

Commission and/or ACER, we expect “fundamental data” to include (but not be limited to) data

collected under the transparency requirements outlined in Chapter 3 of Annex I to Regulation no.

715/2009 of the European Parliament and of the Council on conditions for access to the natural gas

transmission networks.

The transparency requirements for publication of fundamental data by individual gas TSOs were

defined in November 2010 and are outlined in Chapter 3 of Annex I to Regulation No.715/2009. Gas

TSOs are currently required to publish transparency data on an individual basis, and are fulfilling

their transparency requirements by publishing fundamental data on their individual websites. Under

the above mentioned Regulation, TSOs are required to provide information on a website accessible to

the public, free of charge, and with no registration requirements. Data needs to be published on a

regular/rolling basis, in a user friendly manner, and in a clear, quantifiable, easily accessible way and

on a non-discriminatory basis. In addition, the regulation also specifies that data should be provided

“in a downloadable format that allows for quantitative analyses” and in consistent units, in particular

KWh for energy content and m3 for volume.

The table below summarises the data that is required to be published under the Regulation.

Table 6 Data requirements outlined in Chapter 3 of Annex I to Regulation No. 715/2009

Data item Aggregation Period

Technical capacity for

flows in both directions

For all relevant points Forward: At least 18 months

ahead

Historical: 5 years on a rolling

basis

Total contracted firm and

interruptible capacity in

both directions

For all relevant points At least 18 months ahead

Historical: 5 years on a rolling

basis

Nominations and re-

nominations in both

directions

For all relevant points Historical: 5 years on a rolling

basis

Available firm and

interruptible capacity in

both directions

For all relevant points At least 18 months ahead

Actual physical flows For all relevant points Historical: 5 years on a rolling

basis

Planned and actual

interruption of


basis

54

interruptible capacity

Planned and unplanned

interruption to firm

services


basis

Gross calorific value or

Wobbe index

For all relevant points

In addition to the requirements above, the Regulation requires TSOs to publish information on:

The aggregate amounts of capacity offered and contracted on the secondary market (i.e. sold

from one network user to another network user);

Harmonised conditions under which capacity transactions will be accepted;

Maximum amount, booked levels, and availability of flexibility for the market for the next gas

day (when flexibility services, other than tolerances, are provided);

The amount of gas in the transmission system at the start of each gas day and the forecast of

the amount of gas in the transmission system at the end of the gas day.

Furthermore, TSOs are required to provide to each network user, for each balancing period, its

specific preliminary imbalance volume and network user, at the latest one month after the end of the

balancing period.

The requirements outlined above are currently fulfilled on an individual basis by gas TSOs. In

addition, ENTSOG developed a Transparency Platform a few years ago in order to provide centralised

information to all market participants. This is described in more detail below.

As part of the TSOs questionnaire responses, the following key indications were provided:

ENTSOG has indicated that the majority of the TSOs meet the requirements of Regulation

715/2009, Chapter 3, Annex 1, which requires individual TSOs to publish a large amount of

fundamental data via their website. Accordingly, ENTSOG believes that TSOs are already

publishing fundamental data as required under REMIT.

Only a limited number of gas TSOs have indicated in their responses that they provide

separate reporting of fundamental data to National Regulatory Authorities.

The current data formats used on individual websites vary among TSOs. Typically,

fundamental data is available in xls, csv, and/or xml formats, but no common format has been

adopted.

Only a limited number of TSOs have indicated the availability of fundamental data in relation

to production facilities for natural gas, storage, LNG terminals, or consumption of large end

users of gas at exit points.

55

Most gas TSOs responding to the questionnaire have indicated that they publish data in

relation to planned maintenance and interruptions. In particular, a number of participants

referred to the harmonised format developed within ENTSOG (see below).

Under the harmonised ENTSOG format, information is available both with yearly and monthly

granularity. For both firm and interruptible capacity, the following data is provided:

Technical capacity;

Planned interruption;

Remaining capacity (in absolute units (kWh or m3(n)) and percentage term);

Period of maintenance;

Nature of the planned activity.

TSOs have agreed to implement the common format voluntarily on their websites. In addition,

ENTSOG’s transparency platform provides links to the relevant information on individual TSOs’

websites.

A number of TSOs have indicated that in some cases their existing or envisaged reporting obligations

for fundamental data overlap in parts with envisaged reporting obligations under REMIT. The

German TSOs have also highlighted that a law on the creation of a market transparency agency is in

development and a database for the automated delivery of data to the German NRA

(Bundesnetzagentur) is planned by 1st October 2012.

3.6.3. Harmonised fundamental data

ENTSOG has developed a transparency platform on which participating TSOs upload a key set of

fundamental data on a voluntary basis. In particular, ENTSOG has informed us that currently 17

TSOs are uploading requested data on a regular basis.

The transparency platform was originally developed by ECG Erdgas Consult for Gas Infrastructure

Europe (GIE), namely its transmission column (GTE) representing the European transmission system

operators for gas. After the establishment of ENTSOG, The European Network of Transmission

System Operators for Gas, in December 2009, the ownership and management of the Transparency

Platform was transferred to the new TSOs' organisation.

TSOs are currently responsible for the upload of data on a regular basis and in due time, and to ensure

data consistency. The upload of information is currently undertaken via a TSO interface in an xml

format. The download of information per interconnection point from the platform can be undertaken

manually, in xls format.

The transparency platform provides search tools for routes across the European gas transmission

networks, as well as information on individual points.

On selected routes, as well as on individual entry/exit points, the following information is provided:

Monthly available firm capacity (kWh/d);

56

Monthly technical firm capacity (kWh/d);

Monthly available interruptible capacity (kWh/d);

Monthly technical interruptible capacity (kWh/d);

Daily nominations (kWh);

Daily renominations (kWh);

Daily flows (kWh);

Other information, including:

o General information about an operator with links to relevant sections of the TSO’s

website,

o Description of the type of contract (e.g. annual, monthly, etc.);

o Conversion factors adopted;

o Information on balancing rules;

o Information on tariffs.

As highlighted above, this data is uploaded on a voluntary basis by individual TSOs, and is not

currently required in order to fulfil transparency requirements. We understand from ENTSOG that

this may change going forward and the EU transparency requirement may be fulfilled at an EU level

by a centralized platform managed by ENTSOG; however, at this stage this approach has not been

confirmed.

In relation to information on the maintenance of physical infrastructure as outlined above, ENTSOG

has indicated in its questionnaire response that it has introduced a harmonized format for the

publication of maintenance activities. Under this format, information is made available by

interconnection point in both monthly and yearly granularity. For both technical and interruptible

capacity, the following data is provided:

Technical capacity (in units kWh or m3(n));

Planned interruption (in units kWh or m3(n));

Remaining capacity (in units kWh or m3(n) and percentage terms);

Nature of the planned activity (installation works, pipeline works, online inspection).

ENTSOG has indicated that TSOs have agreed to implement the common format voluntarily on their

websites, and the ENTSOG transparency platform provides links to the detailed information on the

individual TSO website. In addition, the removal of any interruptible capacity, whether due to

planned or unplanned maintenance / interruption, is reported on the transparency platform after the

gas day, per point, together with the number of interruptions over the calendar year.

57

3.6.4. Disaggregated fundamental /trade data currently heldby TSOs

As outlined in Section 2, TSOs hold data on capacity allocations and nominations at entry and exit

points on their systems. The capacity allocation mechanisms adopted include first-come first served,

open subscription windows and auction mechanisms. Typically, different types of allocation

mechanisms are applied depending on the type of capacity allocated (e.g. firm/interruptible; long-

term / short-term).

Data items collected in relation to capacity bookings vary amongst TSOs, but would typically include:

Shipper name;

Shipper ID;

Type and ID of the point;

Type of capacity (firm/interruptible);

Type of allocation process;

Start date;

End date;

Granularity (e.g. within day, daily, monthly, etc.);

Reference to contract (if the booking refers to an existing contract);

Duration of contract.

However, currently there is no standard process or platform for the allocation of capacity across

Europe. Work on the harmonisation of capacity allocation mechanisms is currently underway, and it

is described in more detail in Section 4.

In their responses to the questionnaire, gas TSOs have indicated that various formats are also used in

the capacity allocation processes, including xls, xml, and specific capacity booking platforms.

In the case of auctioned capacity, price information may also be included; however, most TSOs did not

provide this as part of their response.

Similarly, data items collected in relation to nominations vary. Only some of the TSOs responding

have indicated standard nomination formats and standards that are currently being used, such as

Gasdat, Kiss-a (xls format), Delfor (Delivery schedule message based on EDIFACT).

Nomination data is typically processed on an hourly or daily basis, depending on the type of balancing

system adopted.

Data items collected in relation to nominations may include, among other values:

Date of generation;

58

Shipper code;

Gas day;

ID point;

Direction point;

ID counterparty;

Quantity.

The majority of TSOs responding to the questionnaire stated that there is no difference in terms of

data collected at interconnection points between EU and non-EU countries.

Currently, the operation of balancing markets is not harmonized at a European level, ranging from

market based mechanisms to regulated tariffs/imbalance charges. Therefore, the data items collected

vary on a country by country basis depending on the type of mechanism adopted. As part of their

responses to the questionnaire, a number of TSOs have indicated the type of data published and the

format used; however, as mentioned above, the type of data collected and data flows vary widely

depending on the type of balancing mechanism in place.

59

4. Definition of requirementsfor power and gas reporting

4.1. Introduction

This section outlines the views from stakeholder categories in relation to the reporting structure for

power and gas. The draft reporting structure builds on the assessments of existing data flows and on

REMIT requirements examined in the previous sections, and takes into account the views collected as

part of discussions with relevant stakeholders as well as from stakeholder questionnaires.

For all stakeholder categories for which workshop have been conducted (traders and brokers,

intermediaries, exchanges, gas TSOs, and electricity TSOs), this section provides an overview of the

key areas of feedback from questionnaires in relation to the principal areas outlined in Article 8 of

REMIT, in relation to both trade/transportation contract data and fundamental data:

Trade/ transportation contract data:

o Records of transactions;

o Lists of contract and derivatives;

o Uniform rules on the reporting of transactions and orders to trade;

o Timing and form for the reporting of transactions and orders to trade;

o Reporting channels.

Fundamental data:

o Reporting of fundamental data;

o Uniform rules on the reporting of fundamental data;

o Timing and form for the reporting of fundamental data.

4.2. Traders and brokers

The traders and brokers provided a range of answers to the circulated questionnaire, yet there was

enough consensus to present a general opinion on behalf of the participants. This consensus is

summarised in this section.

4.2.1. Records of transactions

Participants were concerned about the burdensome consequences of double reporting. In order to

limit the onus of reporting, participants urged consideration of joint procedures and formats between

REMIT (ACER) and EMIR (ESMA). The EMIR draft is not yet finished, so it is our expectation that

the commodities field definitions (Section 2h – Commodities) can be completed in coordination with

60

and with regard towards REMIT. Foremost, coordination should occur with regard to the required

data fields, the reporting format, and reporting deadlines.

Participants also strongly urged the re-use of existing formats used in ETRM systems to reduce effort.

Currently, 50-80% of transactions are captured through EFET cpML, a superset that includes the eCM

and eXRP standards. Following this advice, one common reporting format for both standard OTC and

exchange transactions will be delivered based on a comparison between the ESMA Draft Technical

Recommendation (Annex 2) and EFET cpML, also taking into account the CRE reporting scheme and

our understanding of broker platforms' API XML.

The use of existing coding schemes, such as EIC codes for legal entity and delivery location

identification in energy commodities, was cited by respondents to further reduce implementation

overhead and provide a coherent data set across all participants. Traders and brokers expressed

scepticism about product standardization due to the wide range and number of products.

There is no consensus on the reporting of lifecycle events, nor is there a general trend in the

percentage of lifecycle events. Some report an amendment rate of <.1% of transactions, others report

an amendment rate of up to 30%. There is agreement that amendments to the economic details of a

transaction (price, volume, start or end date, etc.) could be useful for monitoring, but the high

reporting burden must be balanced with the added value of the information. If there is sufficient time

lag between deal execution and data capture, transaction lifecycle events may not be that relevant

overall; however, amendments allow for the correction of grossly wrong entries.

Non-standard transactions do not account for a large proportion of overall transactions and are

harder to use to manipulate the market, but they often involve a higher volume than standard

transactions and therefore should be reported. The definition of “non-standard transaction” was open

to interpretation, and thus led to widely differing answers for portfolio share (0% to 15%). Different

representations in non-standard transactions lead to suggestions of off-line, text reporting with a

limited set of fields. However, the focus should remain on standard transactions as they are easier to

capture, more frequent, and more volatile.

4.2.2. List of contracts and derivatives

The stakeholders did not explicitly state which contracts and derivatives should be included with

respect to Article 8.2(a). However, the implied consensus of opinion of the stakeholders is that in

order to accurately and completely fulfil the intent and stated language of the regulations, ACER

requires full spectrum of contracts including futures contracts, spot contracts, intraday contracts, and

balancing contracts. As TSOs have all of the information needed for reporting centralised balancing

contracts, it was suggested that this reporting obligation fall to the TSOs and not on the market

participants. Further to this point, transactions in OTC balancing/within-day markets and futures

markets conducted through a platform should be reported by the platform and not by market

participants.

The stakeholders have requested confirmation that intra-group deals should not fall under REMIT as

they do not affect the market. Orders to trade for OTC deals should not be reported as it is too

expensive, very complex, and of very limited value.

For nearly all respondents, OTC deals are more prevalent than exchange deals. The range of OTC

deals per month and per participant is between 1,000 and 40,000 whilst the range of exchange deals

is 0 to 25,000. This percentage trends per market and per commodity.

61

No de minimis thresholds should apply to OTC transactions. Large numbers of small transactions

could affect the market, so regulators need a complete picture. These small transactions could also

potentially be exploited to manipulate the market if the threshold is used as a loophole to reporting

obligations. Additionally, most markets have a very limited number of block sizes.

Small traders are concerned about the cost of implementation in terms of market liquidity.

4.2.3. Uniform rules on the reporting of transactions andorders to trade

The stakeholders have indicated that existing reporting requirements and systems for NRAs and

others are already burdensome and non-standardised between agencies. They stress the importance

of coordination between REMIT, EMIR, MiFID, MAD, and to some extent Dodd-Frank, with a

particular emphasis on the alignment between REMIT and EMIR. Non-financial companies are

expected to encounter further complexities as they are not already subject to this type of reporting. In

particular, the cooperation between ACER and ESMA is viewed as the highest priority.

The respondents do not see a need to distinguish between exchange and standard OTC deals for

reporting purposes, but there should be a distinction between auction and continuous-trading

markets. For exchanges that already undertake market monitoring, their dedicated data collection

platforms should be taken into account as a possible data source for REMIT reporting.

4.2.4. Timing and form for the reporting of transactions andorders to trade

The stakeholders were clear and of a single mind regarding the timing of reporting for standard

transactions. Real-time reporting is too burdensome and would require more reporting of

amendments. The earliest practical reporting timeframe is D+1 (best endeavours) / D+2 (maximum

allowed), with D being trading days. For example, if a deal is executed on a Friday before the close of

markets, it should be reported by the end of business day on Monday (D+1), but at the latest by the

end of Tuesday (D+2), regardless of confirmation status. Running and transmitting reports overnight

also balances the load on IT systems, thus reducing overhead.

Codes should be re-used as far as possible. Above all else, EIC codes with no further attributes should

be used for counterparty identification. EIC codes can also be used for e.g. the identification of

delivery point areas. If ESMA enforces product codes for financial products, these should be usable

without mapping in the REMIT space as well.

Existing standards should also be re-used for regulatory reporting: Commodity products Markup

Language (cpML) has built-in coverage of EMIR and Dodd-Frank and could be extended under the

EFET umbrella for REMIT. Between 50% and 80% of transactions to be reported could be covered

using cpML as of April 2012.


The overall responsibility for transaction reporting should remain with reporting parties at all times.

The stakeholders expressed concern about incurring operational and legal risk should the delegated

reporting party fail to report or report incorrectly.

62

Reporting parties trading in different markets and with multi-national entities want to centrally retain

the reporting in-house, citing lower costs due to fixed implementation costs that would not scale with

the volume of data and lower risk exposure. Reporting parties trading in only one or two markets are

more likely to delegate reporting in order to limit obligations and reduce duplication and

inconsistencies.

As previously stated, stakeholders are very apprehensive about the additional burdens of REMIT. The

primary concern is the number of interfaces and reporting mechanisms, rather than double reporting

for individual trades. Each interface requires time and resources for development, integration,

testing, and implementation. Each reporting mechanism adds a layer of complexity and legal risk.

All reporting parties and service providers should be required to pass a defined certification scheme.

The intent of such certification is to verify that the parties are qualified and capable of reporting. In

contrast, the validation of all information submitted to verify compliance to the reporting definitions

is an additional and ongoing process. The suggestion of certification for reporting parties and service

providers is in line with our recommendation that reporting parties themselves can become

Registered Reporting Mechanisms (RRM).

It was also recommended that NRAs should access any data they require from ACER to further reduce

reporting burdens.

4.2.6. Reporting of regulated information (fundamentaldata)

Traders do not view the reporting of fundamental data as their prime responsibility due to the fact

that relevant events originate from generators and TSOs. The traders envision themselves in a

“consumer of information” role but do not anticipate being required to report fundamental data to

ACER themselves.

Regardless of which party is required to report fundamental data, a distinction should be made

between data reported for market monitoring purposes and data reported to inhibit insider trading.

The main difference would be the reporting deadlines: market monitoring data should be available on

a weekly or monthly basis, whereas data regarding the avoidance of insider trading should be available

in real time.

4.2.7. Uniform rules on the reporting of regulatedinformation

Many of generators and TSOs must already report on a national or regional basis, so duplicate

reporting to ACER is not seen as necessary. However, should reporting be required, the generators,

transparency platforms, and TSOs should be the first line of data for REMIT.

Consideration must be taken as to which reported data may be published and which must remain

confidential, at least until it is no longer business relevant.

4.2.8. Timing and form for the reporting of regulatedinformation

As discussed above, traders view fundamental data in two categories: that required for market

monitoring purposes and that required to avoid insider trading. The data for market monitoring

63

should be reported weekly or monthly, while the inside data should be reported as close to real time as

possible.

There is currently no single common data format that REMIT regulations could adopt, but EEX and

NordPool were overwhelmingly suggested as bases for the formulation of a standard format and to

avoid double reporting. More precise definition of the fundamental data to be reported is necessary in

order to create a standard format. Some traders were sceptical as to whether standardisation of

fundamental data is possible.

4.2.9. Further Suggestions

The following table is a summary of comments collected outside of the scope of specific questionnairequestions.

Table 7 Traders and brokers – further suggestions

Topic Content

General • Reporting standards (content, format, frequency) shouldnot be duplicated at a national level – regulators shouldaccess transaction data directly from the trade repositoryand not impose additional requirements on firms

• Technical standards should maximally re-use existingtechnology and standards where these have beendemonstrated to work in an efficient and robust way

Practical Steps • Establish a stakeholder working group for REMITimplementation issues – particularly on reportingobligations

• Break down work more effectively into IT, operative, andlegal/regulatory/compliance issues with separatecommunication and guidance

Regulatorysuggestions

• Given the purpose of REMIT to prevent market abuse, it isnot appropriate to subject intra-group transactions andinternal orders to reporting requirements.

• Intra-group transactions are not wholesale energy productsexecuted in a ‘market place’ (consistent with EMIR) andtherefore should not be reportable under REMIT

• Intra-group transactions are frequently dealt with quitedifferently in internal systems, reporting them wouldimpose considerable additional implementation cost

Other data uses • Firms should have access to data reported to ACER in orderto facilitate in-house analysis

• on an anonymous basis for transaction data

• as long as no commercially confidentialinformation is published

• This may require some high-level aggregation of datawhere appropriate

64

4.3. Third party data providers

4.3.1. Summary of responses from third party data providers

Table 8 Summary of responses – Third party data providers

Topic Content

Records oftransactions

• All or nearly all of the transaction data required byREMIT is currently captured by the third party dataproviders' systems.

• Surveillance list addition suggestions:

• Exercise of any option or swing volumes.Frequency – could occur many times over the lifeof the contract

• Recalculation of contract prices due to indexationformulae, especially complex cross-commoditytransactions (e.g. gas linked to the price of oil).Frequency – monthly

• Contract novation to 3rd parties. Infrequent –once/twice in the life of the contract

Lists ofcontracts andderivatives andappropriate deminimisthresholds

• Opinion split as to whether and how non-standardtransactions should be reported. One indicates that thepossibility for market manipulation is low, anothercontends that contracts with cross-commoditycomponents have complex knock-on systemic risks asfinancial institutions often take the opposite side of theindexation component.

Uniform ruleson thereporting oftransactionsand orders totrade

• Suggest distinguishing between exchange and OTCtransactions because they:

• could lead to exchange and OTC price differences

• have a different demographic

• could influence price formation

• determine commercial hedging versus trading

Timing andform for thereporting oftransactionsand orders totrade

• EFET and CpML are appropriate open formats for tradedata and cover a significant number of transactions.

• Opinion on transactional data reporting frequency is splitbetween real time and D+1.

Avoidance ofdoublereporting andReportingchannels

• Some third party data providers would agree to act as acentral reporting body. Others do not expect to benotifying agents, but do expect to be the primary source oftransaction data. In this case, two data managementchoices were presented:

• Pull - customers extract data to format andsubmit on their own

• Push - direct interface from the third-partysystem to the authorised system, where the third-party system would produce a report in an agreedformat, transmit it, and capture response

65

messages, thus acting as a conduit only andincurring no legal responsibility as an agent.

Reporting offundamentaldata

• Fundamental data collection is difficult due to the variednature of the data. A standard format is recommended forconsistency and completeness, preferrably based on theformats used by exchanges and market operators for theirpublic bulleting boards.

• Ad-hoc data could be formatted according to what is usedby ENTSO TSOs on their message boards.

Uniform ruleson thereporting offundamentaldata

• Fundamental data reporting agents: the data providers donot object to pushing the fundamental data of which theyare aware, but do not see themselves as the primarysource of this data.

Timing andform for thereporting ofregulatedinformation

• Opinion on fundamental data reporting frequency isgenerally as soon as possible, meaning real time or longenough before gate closure to allow affected participantsto act.

Furthercomments

• Consider aligning the initiatives of REMIT and EMIR toconsolidate reporting in this area even further.

• Buyers of Long-Term Gas Contracts (LTC) have to beconsidered as having a substantial position in oil.

• There are significant volumes and values tied up in ‘non-standard’ contracts such that they can’t be marginalised,and electronic confirmation of them is probably morestraightforward than currently believed. Propose a specialworkshop dedicated to the reporting and confirmationtreatment of non-standard contracts under REMIT (andEMIR).

• Vast majority of energy companies do not use electronicconfirmation matching for OTC transactions - not seen ascost-effective for low transaction volumes. Result: 2-3 daylag for the manual trade confirmation process. Requestclarification of what has to be notified and when.

• The definition of ‘transaction’ under REMIT is broaderthan the one under EMIR, thus EMIR transaction datacould be seen as a subset of the REMIT data set. ACERshould work very closely with ESMA to ensure that EMIRTrade Repositories are flexible enough to capture therequired transaction data items unique to REMIT,otherwise there is a real risk of gaps, non-compliance, anddouble reporting.

• Request clarification of the process (includingresponsibilities) of how combined EMIR-REMITtransaction data submitted to an EMIR Trade Repositoryis made available to ACER for REMIT purposes.

• Question of REMIT responsibility in the case of annualconsumption capacity under the control of a singleeconomic entity over 600GWh. Applying the spirit ofREMIT, a substantial demand side response capacitycontract should be a notifiable transaction because DSRcontains an element of volume ‘swing’ or ‘optionality’.

66

4.4. Exchanges

This section summarises the views outlined by exchanges in the questionnaire response prepared byEUROPEX.


EUROPEX suggests primary consideration of the current developments taking place under the Dodd-

Frank Act and EMIR in relation to the definition of transaction reporting. EUROPEX asks DG Energy,

ACER, DG Market, and ESMA to cooperate closely and to jointly introduce the respective reporting

obligations.

Therefore EUROPEX’s recommendation as to the content of transaction reporting is closely aligned to

the EMIR Discussion Paper Draft. EUROPEX suggests a thorough consultation on the topic of

REMIT, as has been done by ESMA in relation to EMIR. Moreover, EUROPEX highlights that non-

alignment with other reporting requirements is likely to cause an extra burden on market participants,

and could eventually fragment trading.

Transaction reports should include a precise identification of the wholesale energy products bought

and sold, the price and quantity agreed, the dates and times of execution, the parties to the transaction

and the beneficiaries of the transaction, as well as any other relevant information (REMIT Art. 8(1)).

"Other relevant information" should enhance data about the background of a trade and allow

identification of the level of abusive actions. For example, being able to identify whether a trade is

cancelled, part of a combination trade, a correction or reversal of a previous trade, or a transfer of a

previously reported trade would enhance market surveillance. EUROPEX suggests that other relevant

information should include the name of the initiator of an order, the name of the account, the client's

name in the case of third party trading, the time during which the order was in the order book, or

nomination data by a TSO.

According to EUROPEX, principally the whole transaction lifecycle is relevant for market surveillance

but should be considered on a case by case basis. The deal lifecycle includes orders to trade as well as

unmatched, changed, and deleted orders. Both trading OTC and via an exchange should be subject to

the same harmonized rules in order to guarantee a level playing field and to avoid regulatory

arbitrage.

An efficient reporting infrastructure needs to distinguish between data which has to be regularly

reported and data which has to be provided in the case of an in-depth investigation only.

4.4.2. List of contracts and derivatives and appropriate deminimis thresholds

EUROPEX considers all markets relevant for reporting obligations as from a market manipulation

perspective there could be price relevant interdependencies. Specific products offered by the various

exchanges need to be taken into account. ACER should have all relevant information that mirrors the

full spectrum of contracts on the balancing and futures markets. These contracts include the

following:

67

- Spot contracts: financial instruments traded OTC, on a regulated market, or MTF (data to be

received via the competent financial authority);

- Intraday contract: standardised contracts traded OTC or via intraday markets;

- Futures contracts: financial instruments traded OTC on a regulated market or MTF (data to

be received via the competent financial authority);

- Balancing contracts: standardised contracts traded in balancing markets run by an energy

exchange or TSO platform.

Introducing de minimis thresholds for reporting for small players who are not final customers would

raise issues such as how to cover small renewable producers. In general, EUROPEX suggests that de

minimis thresholds are unsuitable for both exchange-traded transactions and OTC transactions

because certain abusive behaviour is likely to remain undetected by ACER's monitoring system. If

introduced, a de minimis threshold should be based on volume, not on the number of trades.

EUROPEX states that more and more trading takes place by smaller, decentralised producers who are

small on an individual basis, but on an aggregate basis have a considerable impact on the market and

should therefore be taken into account. These small renewable producers are very active on balancing

markets as well. However, some energy exchanges would welcome appropriate minimum thresholds

as the added value of such data is conceived as marginal. When introducing such thresholds for

transaction reporting, the same approach as suggested for fundamental data (100 MW thresholds)

should be applied. In the case of suspicious behaviour, more detailed information including trade data

for trades under the threshold can be provided if the respective authority specifically asks for this

data.

Defining thresholds for the energy market is considered more complex than for financial markets

since national markets with specific characteristics prevail.


EUROPEX recommends that data fields for the registration of market participants should receive a

unique identification code that can be used generally in the market. As the registration of market

participants is seen to be in close connection to reporting obligations, the coding scheme for

registration should enhance the usability for wholesale energy market participants, such as producers,

trading companies, financial institutions, agency traders, and large end users, while avoiding extra

costs. EUROPEX recommends using registration data not only for assessing REMIT compliance but

also for other sets of regulation that will enter into force in the coming years.

From EMIR, the following points may be relevant to consider:

According to Recital (22) of EMIR, it is important that market participants report to trade

repositories all details regarding derivative contracts into which they have entered.

According to Recital (24) of EMIR, counterparties and CCPs that conclude, modify, or

terminate a derivative contract should ensure that the details of that contract are reported to a

trade repository. When preparing the draft regulatory technical standards regarding

reporting, ESMA should take into account the progress made in the development of a unique

contract identifier and the list of required reporting data in Annex I, Table I of Regulation

68

(EC) No 1287/2006 implementing MiFID and consult with other relevant authorities such as

ACER. This MiFID implementing regulation covers both firm and counterparty identification

by using unique code identifiers. The other fields suggested by EUROPEX as to parties of the

contract are not separately mentioned.

ESMA shall develop draft regulatory technical standards specifying the reporting obligations

and submit those to the Commission by 30th of September 2012. Minimum contents of the

report to the trade repository or ESMA are the parties to the contract and, where different, the

beneficiary of the rights and obligations arising from it, and the main characteristics of the

contracts, including the type, underlying, maturity, notional value, price, and settlement date

(EMIR proposal Art.6(4)).

EUROPEX references ESMA’s preliminary data fields from annex II of the EMIR discussion paper.

The ESMA field list should be used to derive a REMIT reporting standard. EUROPEX further points

out that information obtained for both OTC and exchanges should be harmonized (with a distinction

between voice-brokered deals and those conducted via a trading platform). Further, it is stated that a

distinction between regulated and non-regulated market appears to be necessary.

EUROPEX emphasises the taking into account of the specificities of the reporting of spot products.

These differences are due to auctioning mechanisms that differ from continuous trading. Auction

transactions in the spot market are not matched, so buyers are not matched to sellers. In auction

trading, the results are published with executed buy and sell volumes by each market participant.

EUROPEX underlines that the specific products offered by energy exchanges might differ because of

national market structures and state legislation.


Energy exchanges believe daily transaction reporting (at the end of the trading day) on a daily basis is

best. Moreover, the frequency of reporting should take the different "business hours" in the European

gas markets into account so long as these days are not yet harmonised.

As mentioned before, EUROPEX recommends coordinating data format and coding with ESMA. Some

energy exchanges are active in spot markets, others in both spot and derivative markets, and are thus

operating under different regulatory regimes. Trading platforms use different specifications of e.g.

ticks on day-ahead or intraday market, or price/volume ranges. This could negatively affect the

comparability of trades.


The use of data aggregators like organized markets can enhance the quality and completeness of

reporting. In their response to the questionnaire, EUROPEX members indicated that they consider

themselves as falling under Article 8 (4) point (d) of REMIT, i.e. a party who may report data on

behalf of market participants. According to Article 8 (1) of REMIT, the overall responsibility lies with

market participants, but once the required information is received from a person or authority listed in

points (b) to (f) of paragraph 4, the reporting obligation shall be considered fulfilled.

EUROPEX stresses that neither an obligation to report via pre-defined channels should be introduced

by means of implementing acts nor should the ultimate responsibility for reporting shift from market

69

participants. Instead, transaction reporting should be based on a voluntary arrangement between the

market participant and a third party. According to EUROPEX, energy exchanges should have the

opportunity to decide voluntarily on the scheduling of fees or on how to take legal risks into account.

Exchanges should also be free in deciding whether or not to act as a third party reporting channel on

behalf of market participants. Some energy exchanges are operating under national regulation, and

recovering costs via regulated tariffs. Since they constitute regulated monopolies, EUROPEX

highlighted the importance of such exchanges being allowed to recover those additional costs that

come with the reporting of data on behalf of third parties.

EUROPEX thinks that market participants' flexibility in the choice of a reporting channel will help

develop the most efficient and market friendly solutions. Further, one key element should be a defined

validation scheme which the applying company has to pass in order to be eligible for reporting. Such a

scheme should contain, among other characteristics, security standards and certain IT infrastructure

requirements.

A validation scheme should be defined, which the service provider should pass (security standard, IT

requirements, etc.). Exchanges may offer reporting services for trade data to their clients. Finally,

costs for reporting on behalf of third parties should be recoverable; setting a fee must remain the

responsibility of the service provider.

4.4.6. Reporting of fundamental data

According to Article 8 (5) of REMIT, the reporting obligations on market participants shall be

minimised by collecting the required information or parts thereof from existing sources where

possible. However, developing unified definitions of fundamental data on a national, regional, or

even more so on a European basis, is challenging and might cause high adaption costs. EUROPEX

therefore suggests largely accepting and using already existing regional definitions. The fact that the

data may not be 100% comparable between different zones can be technically adjusted, and should

be taken into consideration when being evaluated by market surveillance authorities. Additionally,

the creation of a wholesale energy market surveillance ad hoc expert group seems to be essential

during the implementation phase and thereafter in order to develop a common understanding of the

energy markets.

According to EUROPEX, the existing ERGEG Guidelines may serve as a good reference during the

technical implementation phase of REMIT as they are indeed adjusted to different regional

peculiarities. Energy exchanges and other data possessing groups may contribute to this effort,

according to EUROPEX. Fundamental data has been less discussed for the gas market than for the

electricity market. EUROPEX highlights that a common process for gas is key for the overall success

of REMIT and should be prioritised by ACER and the NRAs.

The situation, as highlighted, differs from country to country (e.g. transparency platform run by EEX

in Germany/Austria and run by Nord Pool Spot for the Nordic region); accordingly the data might

not be 100 % comparable.


EUROPEX recommends doing market abuse monitoring on a market-by-market basis since too many

differences exist between individual markets in terms of e.g. market structure, production sources,

and number of participants.

70

Setting the reporting threshold for installed production capacity at 100 MW can still create significant

black spots in ACER's market monitoring. As described above, a steadily increasing number of

independent local producers have become active in the market in order to arbitrage price differences.

According to EUROPEX, this applies in particular to decentralized combined heat and power plants.

Fundamental data for the gas market has to be clearly defined.


EUROPEX states that not all European exchanges are involved in collecting fundamental data. The

implementing acts should establish uniform rules to ensure appropriate monitoring. Yearly reporting

of fundamental data is insufficient for efficient market surveillance. Information should be available

at least in the same timeframe as applied for trade data

The future format should be flexible and easily accessible. European exchanges are not aware of a

specific existing data format. While data reported for monitoring purposes can be broken down into

single power plants, LNG terminals, and storage facilities, published data is available on an aggregated

level.

For the reporting of economically sensitive data, secure data connections and adequate encryption

standards must be in place.

4.5. Transport Data

4.5.1. Electricity TSO data

4.5.1.1. Summary feedback on future reporting requirements

Table 9 Feedback on future reporting requirements – Electricity TSOs

Topic Content

Records of

transactions

• No creation of unnecessary burdens

• Use existing channels as far as possible

• ENTSO-E has developed the MADES (Market Data

Exchanges Standard) format, which is widely used among

TSOs to communicate transactional data

Lists of

contracts and

derivatives and

appropriate de

minimis

thresholds

• No views on the list of contracts and derivatives are

expressed by stakeholders

• Existing formats should be used

• Work on data exchange currently under way, especially

via ENTSO-E WG EDI

• Defined thresholds should be introduced according to

REMIT. In general, this may be 100MW but differs for

various regions. Lower thresholds can be considered for

71

certain cases

Uniform rules

on the

reporting of

transactions

and orders to

trade

• Use existing sources in order to avoid double reporting

requirements

• Consider ongoing workstreams

• Standardised reporting format (MADES) has been

established by ENTSO-E

Timing and

form for the

reporting of

transactions

and orders to

trade

• Since the reporting is for the purpose of market

monitoring, periodic reporting is more suitable than real-

time reporting and daily reporting is seen as the best

option. A higher frequency, if at all possible, would

require a sophisticated and thus too expensive IT

infrastructure; a lower frequency might lead to missing

details.

• Distortion of competition through online publication

obligations should be avoided.

Avoidance of

double

reporting and

reporting

channels

• Data is currently supplied to the NRA, in most cases, for

market monitoring purposes although reports may be

published on the TSOs websites

• Suspected market abuse is efficiently reported from the

market surveillance functions at Nord Pool Spot and

Nasdaq OMX in Sweden to the respective NRAs

• Other formal ad hoc processes may be in place

Reporting of

fundamental

data

• ENTSO-E has issued recommendations for the exchange

of data and is complementing its work for the publication

of additional information for fundamental data

• Some data related to electricity market fundamental data

are already published on the entsoe.net platform using

ENTSO-E XML documents. These documents are based

on the core components defined by ENTSO-E WG EDI

(see https://www.entsoe.eu/resources/edi-library/)

• ENTSO-E is monitoring the data being received from

each member TSO to entsoe.net. The target is over 80%,

but the data request is not yet binding and currently

voluntary

Uniform rules

on the

reporting of

fundamental

data

• See above – suggest use of the data available on the

transparency platform

72

Timing and

form for the

reporting of

regulated

information

• Daily reporting is seen as the best option for

• planned fundamental data,

• allocated capacities,

• nominated transmissions,

• final allocated transmissions.

• Unplanned/sporadic changes of fundamental data should

be published ad hoc

4.5.1.2. Records of transactions

In general, the creation of unnecessary burdens should be avoided just as much as double reporting

should be avoided. If possible, existing channels should be used for providing a record of the

transactions undertaken. For market data, ENTSO-E has developed the MADES standard, which

provides for the exchange of information on the basis of an XML scheme. This standard is already

widely used.

Considering the purpose of avoiding unnecessary burdens, the required records of transactions to be

submitted to the Agency should not include data items which are not reflected by MADES and should

furthermore be submitted on the basis of a compatible data format (e.g. based on the ENTSO-E XML

schema).

4.5.1.3. List of contracts and derivatives

Stakeholders have not expressed their view on which contracts and derivatives should be developed in

accordance to Article 8.2 (a) REMIT.

When determining on the reporting requirements, existing formats should be used. Work on data

exchange is currently under way, especially via ENTSO-E WG EDI. ENTSO-E is also tasked with

developing a network code on data exchange and settlement. As concerns developments underway to

standardise reporting, please refer to ENTSO-E WG EDI Implementation Guides as well as MADES

for communication in collaboration with IEC 62325.

Defined thresholds should be introduced according to REMIT. In general, this may be 100MW but

could differ for various regions. Taking into account, for example, emerging distributed generation, a

lower threshold can be considered. There may not be a need for a threshold for reporting transactions

(e.g. for bid offer acceptances or balancing services).

4.5.1.4. Uniform rules on the reporting of transactions andorders to trade

The stakeholder view is to use existing sources in order to avoid double reporting requirements and to

base any reporting requirements on existing standardised reporting formats, or those currently under

development by ENTSO-E. For instance, MADES has been established by ENTSO-E for market data.

73

4.5.1.5. Timing and form for the reporting of transactions andorders to trade

As regards the timing and form for the reporting of transaction of orders to trade, there is a distinct

stakeholder view in place. As communicated via ENTSO-E, the electricity TSOs stress that the purpose

of the reporting requirements is to ensure market monitoring. Therefore, periodic reporting is seen as

more suitable than real-time reporting, and daily reporting is seen as the best option.

A higher frequency, if at all possible (some hourly data are interdependent and monitoring tasks

would not be possible in real time to compensate for the associated costs and efforts), would require a

sophisticated and thus expensive IT infrastructure. A lower frequency might lead to missing

information details and thus undermine the purpose of market monitoring.

Distortion of competition through online publication obligations should be avoided.

4.5.1.6. Reporting channels

Data is currently usually supplied to the NRA for market monitoring purposes, although reports may

be published on the TSOs websites. Suspected market abuse is efficiently reported from the market

surveillance functions at Nord Pool Spot and Nasdaq OMX in Sweden to the respective NRAs.

According to ENTSO-E, other formal ad-hoc processes may be in place.

4.5.1.7. Reporting of fundamental data

ENTSO-E has issued recommendations for the exchange of data and is complementing its work for

the publication of additional information for the fundamental data. Some data related to the

electricity market fundamental data are already published on the entsoe.net platform using ENTSO-E

XML documents. These documents are based on the core components defined by ENTSO-E WG EDI

(see https://www.entsoe.eu/resources/edi-library/). ENTSO-E is monitoring the data being received

from each member TSO by entsoe.net. The target is over 80%, but the data request is not yet binding

and currently voluntary.

4.5.1.8. Uniform rules on the reporting of regulatedinformation

See above – suggest the use of data available on the transparency platform.

4.5.1.9. Timing and form for the reporting of regulatedinformation

Daily reporting is seen as the best option for planned fundamental data, allocated capacities,

nominated transmissions, and for final allocated transmissions. Unplanned/sporadic changes of

fundamental data should be published ad hoc.

74

4.5.2. Gas TSO data

4.5.2.1. Summary feedback on future reporting requirements

Table 10 Feedback on future reporting requirements – Gas TSOs

Topic Content

Records of

transactions

• In general, requirement to avoid unnecessary burdens and, if

possible, use existing channels

• Views vary between players

Lists of contracts

and derivatives

and appropriate de

minimis thresholds

• Existing formats should be used

• Work on data exchange currently under way, especially via the

interoperability working group- standard should follow that

• No de minimis thresholds; if introduced, will need to be market

specific

Uniform rules on

the reporting of

transactions and

orders to trade

• Key to avoid double reporting- requirement to use existing sources

• Consider ongoing workstreams (CMP, interoperability, etc.)

• Do not see themselves as an aggregator for trade data

Timing and form

for the reporting of

transactions and

orders to trade

• Range of views in relation to frequency of reporting of capacity

allocation and nominations data (from daily to yearly). Various

levels of granularity also suggested , changing depending on type of

data (e.g. daily/monthly for capacity bookings, hourly/daily for

nominations)

Avoidance of

double reporting

and Reporting

channels

• Currently no regular standard reporting channel to NRAs in place

for trade data

Reporting of

fundamental data

• Use TSO individual reporting and/or ENTSOG transparency

platform

• Requirements from Chapter 3 Annex I of Regulation 715/2009

should be sufficient

• No de minimis thresholds currently used, mostly would prefer not to

introduce

75

Uniform rules on

the reporting of

fundamental data

• See above – suggest the use of data available on the transparency

platform

Timing and form

for the reporting of

fundamental data

• Similar to capacity data, range of views in relation to the frequency

of reporting (ranging from daily to yearly to even triggered)

4.5.2.2. Records of transactions

In general, a number of TSOs have indicated their preference not to create unnecessary burdens, to

avoid double reporting, and if possible, to use existing channels for providing a record of the

transactions undertaken.

In particular, as regards capacity bookings data, nominations, and balancing transactions data, gas

TSOs have provided a number of views regarding the data items and data formats appropriate for

TSOs to use to report relevant data. Several players have also suggested that existing formats should

be used; these views are outlined in further detail below.

A number of TSOs responding to the questionnaire have also highlighted that work on data exchange

is currently underway, in particular in the context of ENTSOG’s interoperability working groups, and

have indicated that consistency with these other workstreams is required.

As regards security standards, and specifically in relation to how data should be encrypted and

electronically signed, various solutions have been indicated by respondents. In particular, a number of

respondents suggested the AS2 protocol, included as part of the EASEE GAS approved common

business practices. Similar to other points, some participants suggested waiting for recommendations

that are coming from the ENTSOG interoperability working group in this area.

4.5.2.3. List of contracts and derivatives and appropriate deminimis thresholds

ENTSOG did not provide a consolidated view on the list of contracts that should be reported. Some

TSOs questioned the requirement of including nominations as part of the reporting requirements, in

terms of the interpretation of nominations as “use of capacity,” or whether they should be considered

as transactions or contracts.

Gas TSOs did not express a homogeneous view on the potential introduction of de minimis thresholds

in the context of capacity bookings . The majority of TSOs did not consider the introduction of de

minimis thresholds as appropriate (e.g. indicating that with the introduction of thresholds, it would

no longer be possible to reconcile the aggregate capacity bookings with individual capacity portfolios

and use of capacity per shipper). However, other TSOs suggested that minimum thresholds may be

useful, especially if they are set on a member state or market basis.

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4.5.2.4. Uniform rules on the reporting of transactions andorders to trade

In the discussions held with gas TSOs, it has emerged that TSOs do not typically see themselves as

aggregators of trade/transportation contract data (capacity bookings and nominations) in the context

of REMIT. Also in their responses, TSOs highlighted the requirement to avoid double reporting and

to use existing sources as much as possible.

4.5.2.5. Timing and form for the reporting of transactionsand orders to trade

TSOs provided a wide range of opinions on the proposed frequency of reporting and granularity of

trade/transportation data (i.e. primary and secondary capacity bookings, nominations, balancing

transactions), ranging from daily reporting to yearly reporting. A number of respondents also

suggested potential granularity of data, providing different types of answers depending on the type of

data reported (e.g. daily/monthly for capacity bookings, hourly/daily for nominations).

Some of the TSOs responding highlighted that reporting frequency and granularity would depend on

ACER’s needs and goals, and suggested taking the actual requirement into consideration in order to

avoid an unnecessary reporting burden on market participants.

When asked whether they suggested the use of an existing format for reporting capacity booking and

nominations, gas TSOs provided a range of answers, outlining formats such as csv, xls and xml. A

number of respondents (specifically a number of TSOs from Germany) suggested the use of the

existing Edig@s format according to EASEE-Gas CBP 2003-003/02 Edig@s protocol. Other

respondents suggested waiting for recommendations to come from the interoperability working

group, indicating that, whilst an early view has been established that XML is the preferred standard

for data exchange, the specific formats for XML messages are yet to be defined and agreed.

4.5.2.6. Reporting channels

Currently, there is no standard reporting channel for trade/transportation contract data to national

regulatory authorities in place for a large number of TSOs. Some TSOs provide information in

relation to capacity allocation, but no consistent approach is currently undertaken across Europe.

4.5.2.7. Reporting of fundamental data

Gas TSOs have provided a number of views in relation to the data items and data formats appropriate

for TSOs to report fundamental data. Several players have indicated that existing resources should be

used, and xml was the preferred format in a number of cases.

Some players also highlighted that work on a data exchange is currently underway, in particular in the

context of ENTSOG’s interoperability working groups, and have indicated that consistency with these

other workstreams is required.

The majority respondents indicated that there are currently no de minimis thresholds in the

fundamental data they publish, and expressed a preference for not introducing thresholds in this area.

Some respondents indicated that if thresholds are introduced, these should be set on a market-by-

market basis.

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Only a limited number of TSOs responding to the questionnaire indicated the availability of

fundamental data in relation to production, storage, and LNG. Typically this data included capacity

and nomination data (at user or point level).

4.5.2.8. Uniform rules on the reporting of fundamental data

As noted previously, TSO highlighted the importance of keeping reporting obligations to a minimum

and to avoid double reporting by using existing reporting channels in relation to fundamental data

(either the fundamental data published on national TSO websites in the context of the requirements

outlined in Chapter 3 Annex I of Regulation 715/2009, or on the ENTSOG transparency platform).

4.5.2.9. Timing and form for the reporting of regulatedinformation

Similar to the responses received on trade / transportation contract data, TSOs provided a range of

views in relation to the proposed frequency of reporting of fundamental data. Some respondents

suggested relatively infrequent reporting for capacity data (e.g. monthly or yearly), whilst one

respondent suggested a daily reporting for allocations and nominations by point / direction.

A number of the respondent referred to the requirements of Chapter 3 Annex I of Regulation

715/2009, and some respondents suggested that the corrections / amendments to fundamental data

should be “event-triggered”, i.e. that changes should be made when new data is available.

4.5.2.10. Ongoing harmonisation work

A number of TSOs in their responses have made reference to existing workstreams undertaken to

harmonise processes at the EU level. Overall, the gas harmonisation framework has been defined in

the context of third energy package and the 2014 target date for an Internal Gas Market target set by

the European Council.

The Council for European Energy Regulators (CEER) has consulted upon and developed a vision for a

European Gas Target Model, which includes key recommendations (such as the recommendation to

adopt and implement the Capacity Allocation Mechanism (CAM) Network Code and the Commission’s

Congestion Management Proposals (CMP) guideline by 1st January 2014 at the latest.

ACER has also developed Framework Guidelines on Capacity Allocation Mechanisms for the

European Gas Transmission Network, Framework Guidelines on Gas Balancing in Transmission

Systems, and has recently issued a consultation on Draft Framework Guidelines on Interoperability

and Data Exchange Rules for European Gas Transmission Networks. On the basis of these guidelines,

and in the context of the tasks outlined for ENTSOG in Regulation 715/2009, work has been

undertaken by ENTSOG on the development of:

Capacity Allocation Mechanism (CAM) Network Code. A final draft of this document

was officially presented by ENTSOG for ACER review on 6th of March 2012, and will be

subject to Comitology procedure. The document includes provisions relating to:

o Allocation of firm capacity, including proposed allocation methodology at

interconnection points (auctions), and definition of standard capacity products,

applied booking units, and types of auctions introduced;

o Proposed auction algorithms, including items to be specified for a bid in an Ascending

Clock auction (Registered Network User ID, relevant Interconnection Point and

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direction of the flow, Standard Capacity Product, per price-step amount of capacity

applied for) and items to be specified for a bid in a Uniform-Price auction (Registered

Network User ID, relevant Interconnection Point and direction of the flow, Standard

Capacity Product, amount of capacity applied for, minimum amount of capacity

accepted and bid prices);

o Bundled capacity services to be offered at cross-border points and amendment of

existing capacity contracts;

o Interruptible capacity;

o Tariffs / auction prices;

o Establishment of booking platforms.

Draft Network Code on Gas Balancing in Transmission Systems, upon which

ENTSOG is currently consulting. This document includes a number of provisions in relation

to balancing (including principles of balancing systems, cross-border cooperation, imbalance

charges, within day obligations, neutrality arrangements, provision of information to network

users, linepack flexibility, implementation arrangements). In addition, chapter V of this

document includes provisions in relation to nominations, including the following minimum

requirements for information provided in relation to nominations at Interconnection Points:

o Interconnection Point identification;

o Direction of contractual gas flow;

o Network User identification or, if applicable, its Portfolio identification;

o Network User’s Counterparty(-ies) identification or, if applicable, Network User’s

Counterparty(-ies) Portfolio Identification;

o Start and end time for which the nomination is submitted;

o The gas day D;

o The gas quantity to be transported .

Interoperability Network Code, on which work is at an earlier stage; a draft of this

document has not been issued yet. This document is likely to contain, among other things,

principles and rules in relation to the exchange of data between TSOs and network users.

It is expected that work on the above mentioned Network Codes will be completed by 201336.

4.6. NRA view


Necessary contents in general:

Transactions should include all information NRAs need to monitor potential abusive marketbehaviour according to REMIT, e.g. information specific to optional products, references to individualtraders, usernames of various venue systems, reference to the original trade messages (in the case ofan update), venue identification, CCP identification, type of transaction, ultimate beneficiary, etc.

The records of transaction should support the NRAs to avoid and detect the financial types ofmanipulation (e.g. front running, cross venue manipulation, etc.).

Moreover there is a focus on the following abusive practices specific to energy markets

36 Source: CEER Vision for a European Gas Target Model

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- market manipulation and insider dealing in relation with fundamentals (physical assets,transparency, cornering through creation or exacerbation of transmission, or other physicalconstraints)

- cross-market manipulation, e.g. between spot and reserve markets or balancing markets.

NRAs want to highlight that a clear view on what abusive practices might occur is necessary to developappropriate data reporting. This could require inquiries with market surveillance departments andmonitoring authorities.

Minimum Contents:

For bilateral contracts, the principal applies that the information to be reported shall enable NRAsand ACER to fulfil their monitoring tasks under REMIT. Where possible, the same information asexchange-traded contracts should be reported, as well as other relevant information that allows for theidentification of specific and tailored features of those individual contracts. If data relating to priceand quantity are not known at the point of execution, the written materials associated with thetransaction (or agreement) should be accessible.

The list of fields and the procedure to modify it should be flexible enough to allow extending and/ormodifying the minimum information to be reported, according to monitoring needs and theexperience progressively gathered by ACER and NRAs.

Possible Threshold for transaction reporting:

Most NRAs believe that no threshold is needed: thresholds would be too complex to define and mightinduce transaction fragmentation in order to avoid reporting. Some NRAs, however, stress that verysmall market participants should not be subject to the reporting obligation (e.g. feed-in tariffscontracts). The question then depends on the definition of wholesale energy products.

Issue of lifecycle data (trade amendments / cancellations / novations) and / or portfolio snapshotsand nominations:

Lifecycle data is important in order to have a complete picture of trading, to know the exact positionsof market participants, and to identify possible market misconduct. It is not sufficient to usenominations, both data are required.

Issue of information regarding beneficiaries:

NRAs do not have a common opinion:

1. For some NRAs, it may be sufficient for now to provide it on request, but provisionsshould be made to allow that information to be reported now when it is available (e.g.in those cases where the trading venue already has that information, or if the marketparticipant reports a trade itself) and in the future if it becomes necessary formonitoring purposes (e.g. significant increase in third party fund management withwholesale energy products as underlying assets )

2. For other NRAs, beneficiaries of trade should be required in order to avoid potentialmarket manipulation or insider trading. Platforms would need to introduce sufficientprocesses and technical changes to make this information known. Provision of thisinformation just on request would unnecessarily make the analysis difficult. In amarket of many smaller suppliers, the beneficiary may very often be different fromthe initial trader.

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In their response, NRAs referred to Annex II of the draft ACER discussion paper on the recordsof transactions.


Issue of order reporting:

The reporting of trade orders (bid/ask offers) as any process of price discovery is important tomonitoring the market and detecting market misconduct.

Coordination with ESMA when setting up rules:

NRAs highlight the necessary coordination between ACER and ESMA to ensure that reportingmechanisms under EMIR suit ACERs needs in monitoring the energy markets regarding:

- the information included in the reporting

- the timing of reporting

- the cost-effectiveness for market participants

In terms of timing, there should be provisions for a possible period of time where reportingobligations are in force under REMIT only.

NRAs want to stress the need for coordination between ACER and ESMA, and that it is highlyimportant that consultants take the design in financial markets into consideration when designing thetransaction reporting scheme.


NRAs have indicated that daily transaction reporting is sufficient for monitoring purposes. Anyderogation to this rule should be justified and clearly defined. Real time reporting should, however,not be excluded if this proves to be the most cost efficient way of reporting.

Regarding contracts being concluded before the applicability of REMIT, the following can be noted:

All contracts with delivery dates after 28th December 2011 should be reported as soon as reporting isin place, even though they were concluded before REMIT entered into force. The reporting obligationsshould be the same as for similar contracts concluded after the 28th December 2011, whether standardcontracts (venues should be requested to provide a backfill of those transactions) or bilateral non-standardised contracts.

Integration with registration data and shareholder structure:

NRAs believe that the shareholder structure should be included in the registration data. Transactionsdata will be matched with the information from the register for monitoring purposes.

NRAs more generally believe that a strong coordination between the registration format and the shapeof transaction reporting is needed as the information gathered in the registration process mightstrongly influence what information is to be reported on transactions. There is currently aconsultation on the registration format: the proposition is to collect data on “parent undertakings”and/or “related undertakings” and can be identified following the council directive 83/349/EEC 13

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June 1983. However, this is provisional. The final decision will be taken by ACER by 29th June 2012 atthe latest.

Regarding the data format, there is no common view on that question among NRAs. Some prefer CSVformat whilst others mentioned structured XML. The format could actually depend on the type ofdata, e.g. structured XML for trees, graphs, and notably messages, but CSV format for table data.

NRAs generally agree that this should be discussed with all stakeholders and in particular withoperators, and expect consultants to give a recommendation given the huge amount of data to betransferred.

In terms of encryption and electronic signatures, the data transmission must be secured with standardbest practices in order to protect sensitive data and avoid possible legal consequences in case of abreach in communication or to identity spoofing. A first step would be to identify reporting parties;consultancy input is then desirable on IT security.

Regarding standardisation, NRAs have neither discussed nor agreed on reporting data formats,although they acknowledge such a need. They highlight that there are already some advancedexamples of reporting data format standardisation, especially in the countries where oversight ofwholesale energy markets by NRAs started before REMIT entered into force. Therefore, it would beadvisable to adopt harmonised standards that take existing examples into account as much aspossible.

Regarding the question of nomination data, the following can be noted: As a minimum, TSOs (orplatforms operating the nominations) should report nomination data per market participant so thatthe final nomination balance can be known. In addition, collecting nomination data from marketparticipants, exchanges, or hubs could be useful to cross-check the data and ensure the data that isreported is consistent and of high quality.


No specific input has been provided by the NRAs’ response on reporting channels.

4.6.6. Reporting of regulated information (fundamentaldata)

The NRAs make clear that for questions relating the fundamental data reporting, the ERGEG Advice

on Comitology Guidelines on Fundamental Electricity Data Transparency could serve as a basis.

Note: The ERGEG Advice (European Regulators Group for Electricity and Gas – Predecessor of

CEER) was issued on 7th December 2010 (Ref: E10-ENM-27-03, published on the internet)

The guidelines laid down in the document aim especially at establishing a minimum common level of

fundamental data transparency as a precondition of the efficient functioning of wholesale electricity

markets and define a minimum common level of publication of the defined data on a fair and non-

discriminatory basis across all EU member states. Thus it describes, amongst others, the content of

the transparency requirements and timelines for publication regarding load, transmission and

interconnectors, and generation and balancing.


Regarding the critical question of third country market participants' compliance, the NRAs stress the

following:

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It is a very difficult issue with no easy answer. It is of particular relevance for the gas market where a

great part of the upstream market is outside the EU, but also with regard to electricity at the EU

borders.

All market participants should comply with the obligation to report fundamental data, irrespective of

where their headquarters are. They should, in particular, report inside information even if the

information is about upstream facilities outside the EU.

However, a first step would be to impose this obligation on those parties that could be easily

monitored by ACER and on market participants that know those data even if they are not the owners /

operators.

In connection with a possible threshold, the NRAs stress that thresholds should depend on the relative

dimension, integration, concentration, and type of each market. Regional / national markets differ

considerably in size, but within a country thresholds might be different for spot markets and for

balancing markets.

Even though some thresholds could be harmonised for the minimum requirements, the definition of

thresholds should be left to the national authorities and allow them to reduce general thresholds,

taking into consideration the relevant local market features and specificities.


Frequency of reporting:

NRAs did not have a common answer to this question, although they share the ideas that:

- reporting obligations should not be too burdensome for market participants;

- the frequency of reporting should very much depend on the nature and materiality of

fundamental data.

Some NRAs put forward that in order to carry out timely analyses on trade and fundamental data

according to an integrated approach, it would be preferable in principle to gather fundamental data on

a basis consistent with the frequency of trade data collection (i.e. real time to daily). Other NRAs

stress that lower frequency might be more adapted to the nature of event (e.g. planned

unavailabilities, network capacities, or LNG cargo arrivals planning could be reported monthly) or to

ensure data reliability.

Data Format:

There is no common view on that question among NRAs. Some prefer CSV format whilst others

mentioned structured XML. The format could actually depend on the type of data, e.g. structured

XML for trees, graphs, and notably messages, but CSV format for table data.

But NRAs generally agree that this should be discussed with all stakeholders, in particular operators,

and expect consultants to give a recommendation given the huge amount of data to be transferred.

In terms of encryption and electronic signatures, the data transmission must be secured with standard

best practices in order to protect sensitive data and avoid possible legal consequences in case of a

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breach in communication or to identity spoofing. A first step would be to identify reporting parties;

consultancy input is then desirable on IT security.

NRAs have neither discussed nor agreed on standardised reporting data formats, although they

acknowledge such a need. They highlight that there are already some advanced examples of reporting

data format standardisation, especially in the countries where oversight of wholesale energy markets

by NRAs started before REMIT entered into force. Therefore, the adoption of harmonised standards

that take existing examples into account as much as possible is advisable.

Regarding the question of nomination data, the following can be noted: As a minimum, TSOs (or

platforms operating the nominations) should report nomination data per market participant so that

the final nomination balance can be known. In addition, collecting nomination data from market

participants, exchanges, or hubs could be useful to cross-check the data and ensure the data that is

reported is consistent and of high quality.

In connection with the data to be collected regarding the capacity and use of transmission systems, the

following should be noted:

Information to be reported shall in principle enable NRAs and ACER to fulfil their monitoring tasks

under REMIT.

The capacity itself as well as all capacity allocation mechanism results (long and medium term, daily),

and eventually nominations and the use of capacity, should be subject to reporting.

More generally, the list of fields and the procedure to modify it should be flexible enough to allow

extending and/or modifying the minimum information to be reported, according to monitoring needs

and the experience progressively gathered by ACER and NRAs.

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5. Advice on reportingrequirements

5.1. Advice on reporting requirements


Terminology concerning transaction types

Traders interact with each other and with TSOs/SSOs/LSOs in energy wholesale markets for gas and

power. Their interaction results in commodity, transport, and storage contracts. A generic definition

of wholesale energy products is included in Art. 2 (4); hovever for the purposes of our analysis we use

the term “transactions” in order to refer to the complete life-cycle of a transaction, and the term

“contract” to describe the contracting stage of a transaction life cycle as further described below:.

Following this terminology the reporting obligation under REMIT comprises the following:

Commodity transactions for the supply of electricity or natural gas where delivery is in the

Union (including LNG transactions)

Derivative transactions relating to electricity or natural gas produced, traded, or delivered in

the Union (including LNG transactions)

Transactions relating to the transportation of electricity or natural gas in the Union

Derivative transactions relating to the transportation of electricity or natural gas in the Union

Transactions relating to the storage of natural gas in the Union

Derivative transactions relating to the storage of natural gas in the Union

Storage transactions for natural gas and derivatives are considered a major part of the trading

activities in the energy wholesale markets and they need to be included in such a definition

accordingly.

Recommendation:

Develop a non-exhaustive list of transaction types and transaction stages as part of

the explanatory documents accompanying the further implementation of REMIT to

specify the reporting obligation

Include LNG and storage transactions and derivative transactions relating to LNG

and storage in the list of wholesale energy products.

Terminology concerning transaction lifecycle stages

Regarding the lifecycle of such transactions, it is not considered sufficient to merely incorporate

concluded contracts in the reporting, as certain commercial decisions are taken before and after

contract conclusion. Likewise, the speed of implementation of reporting may be different for different

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venues and stages of the deal lifecycle. Reported transactions may have an incomplete coverage of the

market for some time, but this will be partly addressed by gathering information about the same

transaction at different stages of the deal lifecycle.

Three main stages of the deal lifecycle of transactions in wholesale energy products shall be addressed

in the reporting (“transaction stages”):

Orders as well as bids/offers before a deal is entered into (“order stage”);

Concluded transactions (“contract stage”);

Execution of a contractual right for physical delivery which may include the use of

optionality/ flexibility at the agreed point in time after contract conclusion (“scheduling/

nomination stage”).

In what regularity/ format and from whom such information is collected is covered in the later

sections of our recommendation.

Recommendation:

Specify in further explanatory documents the three transaction stages of order,

contract and scheduling/ nomination in such a way that the reporting obligation

under REMIT principally includes these three stages for each transaction.


Geographical scope of reporting obligation

Regarding to the scope of the reporting obligation REMIT refers in the existing legal definition of

Art.2 (4) to “contracts (...) where delivery is in the Union” as well as “contracts relating to the

transportation (...) in the Union” (and derivatives relating to such transactions). In our understanding,

this definition can be made even more specific by designating the area of physical delivery within the

power and gas transmission networks within the Union as a constituting factor for the reporting

obligation. Besides designating the area of physical delivery within the Union in such a way in the

Implementing Act, a list of such power and gas transport networks within the Union together with

their relevant network codes can be created, maintained, and published on a regular basis by ACER,

making the checking of reporting obligations a clear-cut task for market participants.

Recommendation:

Specify a list of transmission systems for power and gas in the European Union as a

basis for the definition of the reporting obligation.

Define the reporting obligation as being applicable for all gas and power transactions

(and derivatives relating to such transactions) which may result in delivery,

transportation rights, or storage rights in a transmission system under the operation

of a power/ gas TSO, SSO, or LSO included in the previous list.

ACER product taxonomy

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A taxonomy helps to categorise energy wholesale transactions following a set of criteria such as

commodity, transaction type, market, etc. The introduction of a standard financial product taxonomy

is discussed within neighbouring regulatory regimes such as the Dodd-Frank Act and EMIR in order

to classify transactions in a standardised way.

The question is still open as to whether such a standard categorization (joint with Dodd-Frank and

EMIR) makes sense as energy products are characterized by their physical deliveries. If delivery points

and markets are additionally used for categorization, a taxonomy can only be used locally within the

scope of REMIT or as an extension to a standard category. This has to be clarified in connection with

neighbouring regulatory regimes.

Should an existing, external taxonomy be adapted for REMIT, market participants or indeed third

parties to which the reporting is delegated will have to perform a mapping from their proprietary

product codes to the ACER standard product taxonomy in order to report against this standard

product taxonomy.

If the ACER taxonomy does not cohere with other regulatory regimes, it can be implicitly derived from

the following dimensions, each with standardized closed lists of values:

Commodity type (power, gas). In the case of financial transactions like options on indexes, the

commodity type of the underlying index is chosen. Capacity transactions in the power TSO

network are of the commodity type power, likewise for gas.

Transaction type (physical, financial),

Transaction category (Commodity, TransportCapacity, StorageCapacity, LNG Terminal

Capacity),

Country code (ISO country code 3166-1 of the country of physical delivery or underlying for

derivatives),

DeliveryPointArea (EIC codes of market areas and delivery points).

Characteristics like delivery period, delivery point, quantity, and price are not specified as a closed list

and will be included in the REMIT Reporting Document Format description in the annex.

Recommendation:

Define a standard product taxonomy which is binding for the industry in order to

categorize transactions by their product types. Contrary to proprietary energy

product codes on exchanges, this ACER product taxonomy will not be a list of codes

such as “F0BM” or “DBF Nov-12”, the proprietary codes for monthly base load on EEX

and APXENDEX, respectively. Split the product taxonomy into separate dimensions,

each dimension having a finite and well defined number of possible values.


Coding scheme for market participants from ongoing ACER registration procedures

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In order to fully use, analyze, and – where appropriate - distribute the data collected under Article 8,

it is of primary importance to identify market participants and locations relevant for the

aforementioned purposes by applying a standardized, global coding scheme.

This project was run partly in parallel to consultancy services on the technical implementation of a

register of market participants performed by a different firm on behalf of ACER. Due to timing

constraints, the results of the two projects could not be fully synchronized, resulting in the following

assumptions/ recommendations for the coding on our part:

The ACER code database (European Register System, “CEREMP”) should be available to the

REMIT database in a consistent and closely connected form. Should the connection to the

database maintaining ACER codes be too slow, essential data may have to be extracted from

the CEREMP database and duplicated within the ACER database.

Market participants, NRAs, and third parties to which reporting obligations have been

delegated (e.g. exchanges, providers of fundamental data), in other words all organisations

with a role in the ACER system, receive an ACER code as well.

Coding of these entities should include the usage of existing code schemas (e.g., EIC codes,

broker codes) such that import mapping of data provided by report sources can be performed

correctly. As there are only a few broker codes in use, these should be replaced by EIC codes.

This has already started in the industry for some processes.

Code standards for traders: EIC codes are commonly used in OTC transactions across Europe.

Apart from this, each trading venue uses proprietary member identification codes. An

emerging standard is the LEI code (Legal Entity Identifier), which is required as part of the

Dodd-Frank Act and EMIR standardizations. For parties, it is assumed that EIC codes are at

least used as a secondary code.

Locations (physical delivery points) within the power and gas TSO networks should be

encoded using EIC codes.

Recommendation:

Use the EIC code as a basis for the ACER code, used to identify market participants in

the REMIT reporting format or at least supply as a secondary code

Delimitation of markets with different tenure

Referring to previous explanatory paragraphs in this reports on the transaction lifecycle, three time

periods of markets may be split up to further specify the scope of the reporting obligation:

The bilateral contracts (forwards/ futures) markets for commodities with or without physical

delivery which operate from a year or more ahead of real time (i.e. the actual point in time at

which commodity is delivered), typically up to 24 hours ahead of real time;

Short-term markets which are operated until a point in time when market participants notify

the TSO of their intended final physical position; such markets enable sellers and buyers to

fine-tune their rolling delivery positions as their own demand and supply forecasts become

more accurate as the delivery time is approached;

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Balancing markets operated from gate closure through to real time and operated with the TSO

acting as the sole counterparty to all transactions.

Principally, all market phases fall under the reporting obligation under REMIT while the balancing

markets are already under close supervision of the NRAs. TSOs are always a party to such transactions

and may be considered less relevant to market supervision by ACER.

Recommendation:

Specify in further explanatory documents that balancing markets are within the

overall reporting obligation but do not make balancing transactions a part of an

initial reporting phase

Specification of reporting obligation of market participants in the transaction stages

The reporting obligation of market participants will need to be further specified for the three

transaction stages defined above. Principal envisaged reporting requirements could be as follows:

Order stage:

For commodity, transport, and storage transactions, the reporting obligation for the order

stage is with the trader who has submitted such order or bid/offer in a market or trading

venue. Having said this, the delegation of reporting of orders to RRMs (exchanges, broker

platforms) may be the natural course of action. In the instance of auctions, exchanges would

be the only provider of full auction data.

Contract stage:

The reporting obligation for the contract stage is with both parties of a transaction. In contrast

to the Dodd-Frank rules, there is no definition of a preferred reporting party per transaction.

o For commodity transactions, both the buyer and the seller report.

o For transport transactions in primary capacity, the buyer of capacity and the TSO

report, for secondary capacity transactions, both the buyer and the seller report.

o For storage transactions in primary capacity, both the buyer of storage capacity and

the SSO/LSO report, for secondary capacity transactions both the buyer and the seller

report.

Scheduling/ nomination stage:

The reporting obligation for the scheduling/ nomination stage is with the trader who

schedules/ nominates and with the TSO who receives such scheduling/ nominations

information. As all scheduling/ nominations information is with TSOs they may be seen as

natural provider of such reporting.

Recommendation:

By transaction type, the respective stages of a transaction and for both parties

involved in a transaction clarify the reporting obligations of market participants.

Reporting obligations for the order and contract stage:

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A “standard commodity transaction” is a transaction where the offer and contract transaction stage

can be transformed into the applicable REMIT standard reporting format (long form) without losing

their resemblance to the key economic terms of the original transaction.

A split of “long form” and “short form” reporting is made in order to ensure practicality in the

reporting obligation for commodity contracts. Each standard commodity transaction has to be

reported either in long form or in short form, depending on the designation by ACER outlined below.

Non-standard commodity transactions are always reported in short form.

The split of long form and short form reporting is only applicable to the contract stage of the trading

of power and gas. For the order stage, the scheduling/ nomination stage, and for the contract stage as

far as capacity is concerned, only one form of reporting is applicable.

For each phase of the implementation of REMIT, ACER should clearly define a subset of the standard

commodity transactions for which long form reporting is mandatory. For these standard commodity

transactions, detailed (possibly multi-line) and frequent (daily) long form reporting under the REMIT

standard reporting format is prescribed. Standard commodity transactions, for which long form

reporting is not mandatory in a given phase, have to be reported either in short form, or – voluntarily

and at the discretion of the reporting party - in long form.

Short form reporting under the REMIT standard reporting format shall be used for all non-standard

commodity transactions. Further, short form reporting shall be used for those standard commodity

transactions, for which long form reporting is not mandatory and which have not been reported

voluntarily in long form either. Compared to long form reporting, short form reporting is less detailed

(one line item per transaction) and can be less frequent (at maximum monthly).

Over time and with subsequent implementation phases, mandatory long form reporting will be

applied to an increasing share of standard commodity transactions until it covers all or almost all of

the standard commodity transactions.

Table 11 Envisaged long form and short form reporting in REMIT implementation phases

REMIT

Implementation

Phase

Long form reporting is

mandatory for standard

commodity transactions

defined by

Reported as short form

Phase 1 “White list”, see below Anything not on the “white list”

Phase 2 “White list” + “1st extension” (subset

of “grey list” to be designated by

ACER)

Anything not on “white list” + 1st

extension

Phase n+1… White list + 1st extension + 2nd

extension (as designated by ACER,

likely full “grey list”)

“Black list”

Convergence to fullest

possible extent of

standard reporting

For all standard commodity

transactions, the reporting in long

form is mandatory

Only non-standard commodity

transactions are reported in short

form

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Non-standard commodity transactions and standard commodity transactions, for which long form

reporting is not mandatory in the given implementation phase, shall be reported in short form under

the REMIT reporting obligations.

The designation of standard commodity transaction for which long form reporting is mandatory needs

to be unambiguous and simple to apply. Long form reporting should apply to a defined set of standard

commodity transactions which are processed by the following intermediaries and trading venues for

electronic deal conclusion or deal settlement. (“white list”). In phase 1, long form reporting is

mandatory for all:

Transactions on electronic brokerage platforms (e.g. Trayport)

Transactions on exchanges (e.g. members of EUROPEX)

Transactions confirmed by means of electronic deal matching systems (e.g. using EFET eCM)

Transactions nominated electronically for clearing by means of automated deal clearing

systems (e.g. EFET eXRP)

The designation should also take into account the prevalence of data aggregation in order to

streamline the delegation of reporting obligations. In phase 1, it should be possible to delegate all

reporting obligations regarding commodity transactions to a data aggregator, without prejudice to

reporting parties performing their reporting obligations themselves.

The following transactions are further examples of standard commodity transactions, for which long

form reporting is, however, not mandatory in phase 1 (“grey list”). These transactions must be

reported, but they can be reported in short form in phase 1. The designation of which standard

commodity transactions must be reported in long form will be extended in later phases by ACER

guidance.

Bilateral transactions without broker or outside brokerage SEFs, but under a standard master

contract (closed list: EFET, ISDA, ZBT, NBP, GTMA) with unchanged reference terms

All transactions nominated electronically for clearing by means of an automated deal clearing

system specific to a certain clearing provider (e.g. bespoke clearing interfaces of individual

banks)

Examples of non-standard commodity transactions (“black list”), which must be reported in short

form:

Bilateral transactions without a broker and not under a standard master contract (closed list:

EFET, ISDA, ZBT, NBP, GTMA), but in long form, where the terms and conditions of the long

form contract deviate materially and substantially from the standard master contracts.

Bilateral transactions without a broker and not under a standard master contract (closed list:

EFET, ISDA, ZBT, NBP, GTMA), but under a bilateral custom master contract, where the

terms and conditions of the custom master contract deviate materially and substantially from

the standard master contract

Long-term contracts with varying prices and/or flexibiblity provisions expressed as

daily/monthly/yearly minimum and/or maximum-take quantities

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Bilateral transactions with take or pay clauses over extended time frames which require

splitting into several sub-transactions when entered into nomination or scheduling systems

As a technical specification the following XML message types are foreseen for reporting of market

participants or of third parties to which reporting has been delegated to (see Table 12 below).

Table 12 Overview of envisaged XML message types

Message Type under

REMIT Reporting

Short description Trans-action

Stage

Reporting

frequency

Commodity

Type

Type of

recommend

ation in this

report.

Short Form or

Long Form

CommodityOrder Bids to buy and sell, bids for auctions

both exchanges and electronic broker

platform

Order stage Daily on

trading days

T+1 (2)

Power, gas

commodity

Summary Long form only,

complete standard

reporting at time of

introduction

LongFormCommodityC

ontract

Executed deals, both OTC deals and

exchange deals

Contract Stage Daily on

trading days

T+1 (2)

Power, gas

commodity

Detailed Standard

Transactions included

in the “white list”

must be long form,

rest short form

CapacityBiddingPower Bids for capacity rights in explicit

capacity auctions

Order stage Consideratio

n for later

stage

Consideratio

n for later

stage

Consideration for

later stage

CapacityBookingPower Booking of capacity with power TSO,

only primary auctions based on

ECAN (document “allocations

results”)

Contract stage Less frequent Power

transmission

capacity


complete reporting at

time of introduction

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Message Type under

REMIT Reporting

Short description Trans-action

Stage

Reporting

frequency

Commodity

Type

Type of

recommend

ation in this

report.

Short Form or

Long Form

CapacityBiddingGas Bids for capacity rights in explicit

capacity auctions (e.g. TracX)

Order Stage Consideratio

n for later

stage

Consideratio

n for later

stage

Consideration for

later stage

CapacityBookingGas Booking of capacity with gas TSO,

only primary auctions

Contract stage Less frequent Gas

transmission

capacity




StorageBooking Booking of gas storage and LNG

terminal capacity

Contract stage Less frequent Gas No, clarify

market

participant

role first

Long form only,



ShortFormCommodityC

ontract

List of Non-standard commodity

transactions

Contract stage Monthly All Detailed Used for all short

form reporting

Market participants or their delegated RRMs will receive a receipt message of the message type

REMITBusinessAcknowledgement for each transaction report, detailing the number of reported

transactions including their identifiers. This receipt message will enable reporting parties to reconcile

their reporting obligations with actual reports made. In case of an unsuccessful report, a failure

message of the message type REMITRejection Message will be sent to the reporting parties enabling

the fixing of the problem and retry.

For the long-form reporting of commodity transactions a report document format covering both OTC

and exchange based transactions has been developed. It is based on a detailed comparison with the

data standards prevalent in the market: EMIR (ESMA Draft Technical Recommendation), broker

platforms , EFET CpML (super-set of EFET eCM and eXRP), exchange platforms, and CRE reporting

scheme, and with ENTSO-E ESS and EDIG@S.

Regarding transport and storage transaction formats, further effort towards standardization is

ongoing in the market. Because of these efforts not being sufficiently advanced at the time of the

implementing act, the proposed standard reporting formats (message types CapacityBooking and

StorageBooking) have less detail than other messages.

Non-standard commodity transactions and transactions for which long form reporting is not yet

mandatory in phase 1 will have to be reported in short form using the

ShortFormCommodityTransaction message type. Such short form reporting shall enable the

regulators to follow up with further investigation into the details of selected transactions on a case-by-

case basis. Therefore, all transactions reported in short form have to be identified per transaction on a

line item level and with a unique reference to the transaction (deal ID and trade date) and to the

counterparty. To allow the selection of worthwhile transactions for a spot check, in addition the total

value of the transaction has to be given. This way, the amount of transaction activity reported only in

short form is measured at regular intervals. Should this amount increase in comparison to the bulk of

transactions reported in long form, countermeasures and detailed checks can be taken. The objective

is to cover as much activity as possible under long form reporting.

Short form reporting using the ShortFormCommodityTransaction message type should be performed

at maximum on a monthly basis and in a machine-readable format. For each transaction reported in

short form, this message needs to contain one line with at least:

Unique Contract ID as assigned by the reporting party to the transaction reported in short

form allowing for manual ad hoc querying by ACER

ACER ID of deal counterparty for this transaction reported in short form

Transaction Date of the transaction reported in short form

Commodity (Gas, Power)

Transaction type (physical, financial)

Category of transaction reported in short form (Commodity, TransportCapacity,

StorageCapacity,age, LNG Terminal Capacity)

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Start and End Date of delivery. For physical transactions, these are the actual start and end

dates of delivery in local time at the point of delivery. For financial transactions, these are the

earliest and latest dates of possible execution.

Indication of contract value in EURO. If the transaction is valued in a currency other than

EURO, the contract value has to be calculated by applying the FX rate current at the time of

reporting, and given in EURO as well.

The introduction of thresholds would help to limit reporting workload for market participants in

particular in the context of short-form reporting, where automated reporting out of a trading system

holding such transactions may be limited. However the introduction of de-minimis thresholds is seen

as problematic due to the different size and regional specifics of European gas and power markets.

The Appendix to this report includes:

For long form reporting to be enacted in Phase 1: Detailed field lists for reporting the Contract

Stage for Commodity Transactions, for the message type LongFormCommodityContract

For long form reporting to be enacted in Phase 2: Summary recommendations with draft key

fields for reporting the Order, Contract and Scheduling/Nomination Stages for Commodity

Transactions, for the message types CommodityOrder, CapacityBookingPower,

CapacityBookingGas

For short form reporting which is enacted in phase 1: detailed draft field list for reporting for

the message type ShortFormCommodityContract

Recommendation:

Split the overall reporting obligations for commodity transactions into long form and

short form reporting from the start of the reporting regime.

Publish a list of intermediaries and request explicitly that at minimum all commodity

transactions processed by these intermediaries need to be reported in long form

(“white list”). Keep such an intermediary list extendable by giving notice hereof in a

versioned ACER guidance document.

Apply the REMIT Reporting Document Format for commodity, transport and storage

transactions while mentioning that the scope of long form reporting may be adjusted

by issuing new versions of the REMIT reporting standard in case further

standardization is achieved.

Reporting obligations for the Scheduling/nominations stage:

Scheduling/nominations data originates from the execution of physical delivery under commodity,

transportation and storage contracts. Notice periods are defined under the specific network code (e.g.

nomination for gas becomes valid two hours after the full hour). Such information is held by traders

on a contractual level and transmitted to TSOs as an aggregate of buy and sell volumes to be

scheduled with a trading counterparty at a defined market or network point location.

Scheduling/nominations data generally refer to a market area or physical network connection point

and are triggered by the following events:

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Deliveries under commodity contracts between two traders shall be executed (standard and

non-standard commodity contracts as defined above);

Upstream gas production or power plant production shall be entered into a transport

network;

Transport capacity shall be used;

Storage capacity linked to a transport network shall be used by injecting or withdrawing

natural gas.

For the sake of clarity, it should be mentioned that scheduling/nominations activity requires a

deliberate action from a market participant as opposed to end users who are demanding energy

deliveries upon their own discretion (i.e. without explicitly telling their counterparty in advance how

much energy they intend to consume).

As a technical specification the following XML message types are foreseen :

Table 13 Envisaged XML message types – scheduling/nominations

Message Type

under REMIT

Reporting

Short description Trans-

action

Stage

Reporti

ng

frequen

cy

Comm

odity

Type

Type of

recomm

endatio

n in this

report.

Short

Form or

Long

Form

SchedulingNomina

tionPower

Scheduling nomination

with power TSO, based

on ESS

Schedu

ling /

Nomin

ation

Stage

Daily on

all days

Power Detailed Long

form only,

assumed

fit of all

schedulin

g/nomina

tions in

ESS

SchedulingNomina

tionGas

Scheduling nomination

with gas TSO, based on

subset of EDIG@S

Schedu

ling /

nomina

tion

stage

Daily on

all days

Gas Detailed Long

form,

assumed

fit of all

schedulin

g/nomina

tions in

Edigas

A field list for reporting the scheduling/nominations stage has to naturally cover all types of

transactions previously mentioned with the message types SchedulingNominationPower and

SchedulingNominationGas. Physical flows between markets as well as within markets are considered

to be vital in understanding cross-border linkage between markets and providing an overview on

overall transaction activity of traders.

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In the interest of an efficient reporting process, TSOs are considered as being naturally in the position

to deliver such aggregated data on a daily basis under REMIT. If TSOs (and traders in parallel) shall

deliver such data, they would follow a structure of market places or market areas or network

connection points to which scheduling/ nominations activity based on the above mentioned triggering

events refer. The TSO is for a specific network in the best position to define such physical structure.

While different formats are adopted by the individual TSOs, standard nomination formats for gas

(EDIG@S) and power (ESS) have been used as orientation for defining a REMIT reporting standard

for the scheduling/nominations stage.

The Appendix to this report includes:

For long form reporting to be enacted in Phase 1: Detailed field list for reporting the

Scheduling/Nomination Stage, for the message types SchedulingNominationPower,

SchedulingNominationGas.

Recommendation:

Apply the REMIT Reporting Document Format as described above for the

scheduling/nominations transaction stage of all gas and power transactions from the

start of the reporting regime.


Real-time reporting causes high overheads under other regulatory regimes for both the industry and

repository operators, leading to an adversely high economic impact of regulation. In addition, there is

a trade-off between real time and data quality: the longer the time span between an event and the

reporting of the event, the fewer errors (“noise”) will be in the reported data. For example, one nightly

report on T (trading days following the European commodity trading calendar) would already reduce

noise; a nightly report on T+1 would further eliminate the necessity to report short-term document

lifecycle events. Thus it is proposed to follow matching suggestions from exchanges and traders (T+1

best endeavour, T+2 maximum).

Reporting of commodity transactions in short form should be performed on a monthly schedule (total

number of deals reported in short form and for each deal unique identifier and counterparty and some

more details, see above). Reporting of final daily nominations should be once a day.

Double reporting of a transaction will be counteracted by subsequent pairing of transactions at ACER.

If this data reconciliation through pairing is not fully successful, this should not cause significant

damage to the data integrity of the ACER database, as portfolio valuation is out of scope under

REMIT. If reported data is well identified, the ACER database can reconcile reports from different

sources by pairing reports of the same transaction. However, as opposed to deal confirmation, a

perfect pairing of all multiple reports of one transaction is neither possible with automatic

mechanisms, nor necessary to perform the required analysis.

The reporting of wholesale energy transactions should cover all three major transaction stages: order,

contract, and scheduling/nomination. Reporting in the latter two transaction stages (contract and

scheduling/nomination) should be implemented in phase 1, with reporting in the transaction stage

order to follow in phase 2. Thus even in phase 1, the majority of wholesale energy transactions will be

reported twice: first in the contract stage, and then in the scheduling/nomination stage. In phase 1, all

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physical wholesale energy transactions will be reported at least once, namely in the

scheduling/nomination stage.

However, the reporting of deal /document lifecycle events beyond this concept of major transaction

stages is a separate question. Other regulatory regimes such as Dodd-Frank follow a very fine-grained

deal lifecycle approach, where even within the contract stage a single deal has to be reported at least

three times: at RT (Real Time), PET (Primary Economic Terms, essentially at deal execution but with

more details), deal confirmation. In addition, all other continuation data like daily valuation changes,

amendments, cancellations and novations have to be reported as well. The added value in having

higher transparency and more up-to-date/accurate data by following this approach needs to be

balanced against the higher economic impact on market participants and resulting implementation

delay implied by the burden that such deal / document lifecycle reporting generates. Apart from this,

the receiving system(s) of ACER and the NRAs would have to be complex and of high resilience to

handle such stream of update messages for transactions potentially years old.

Some deal / document lifecycle events, like recoding of delivery points or correcting differing trade

dates or rounding errors, are of no substantial interest under REMIT. Given the incident rate of

amendments and cancellations in OTC trading (reported to be in the order of 3 to 10% of all

transactions from execution to final settlement), the rate of “interesting” events should be lower by a

factor of two or three. The implementation of REMIT should err on the side of simplicity. During

phase 1, the roll-out level achieved across the market will be the prime measure of success. We suggest

it is better to achieve 95% REMIT-compliant reporting under simple rules with some 1% to 3%

transactions displaying some deviations in the ACER system compared to the actual transaction

caused by deal / document lifecycle events, rather than 50% reporting under very complex rules with

fewer deviations.

Some of the trading venues, exchanges, and brokerage platforms which are definitive for the “white

list” transactions do not have full visibility of all deal / document lifecycle events at the reporting

parties. Thus imposing reporting of those events would prevent market participants from delegating

the reporting of the standard transactions for which long form reporting is mandatory to these trading

venues, exchanges, and brokerage platforms acting as RRM.

Thus we recommend that ACER defines deal / document lifecycle events as being out of scope in

phase 1. Towards the end of phase 1, this approach should be reviewed. If need be, amendment and

cancellation variants of the existing message types can be introduced then without sacrificing

backward compatibility. This is possible by foreseeing document versioning in phase 1, which can be

statically populated by version “1” in that phase only.

Having said this, errors do happen, and transaction reports in either long form or short form

containing gross errors such as order of magnitude errors or the wrong assignment of counterparties

due to faulty coding should not be allowed to linger in the ACER database for years. Otherwise, this

may impede correct analysis for a long time. Such grossly wrong transaction reports would be wrong

already at the time of transmission, not due to changing valuations thereafter. In such cases, reporting

parties should be obliged to communicate such errors and the corrected wholesale energy transactions

to ACER offline, i.e. not following the standard transaction formats, in channels as ACER sees fit. In

the beginning, this might be as simple as a signed e-Mail or web form. If need be, ACER personnel can

then dispose of those errors by accessing the ACER database directly.

Recommendations:

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Define reporting obligation for wholesale energy transactions in all three major

transaction stages: order, contract, and scheduling/nomination. Reporting in the

latter two transaction stages (contract and scheduling/nomination) should be

implemented in phase 1, with reporting in the order stage to follow in phase 2.

Define the cycle for long form reporting of the order and contract transaction stage

for all commodity, transport and storage transactions to be T+1, i.e. by close of the

following business day.

Define the cycle for reporting of the scheduling/nomination transaction stage for all

commodity, transport and storage transactions to be T+1, i.e. by close of t day.

Define the cycle for short form reporting to be at maximum monthly, i.e. by close of

the first business day in the calendar month for the preceding calendar month.

Consider wholesale energy transaction lifecycle events such as amendments,

cancellations or novations as out of scope for reporting at least in phase 1.

Provide a way for reporting parties to communicate gross errors such as order of

magnitude errors made in previous reports of wholesale energy transactions to ACER.


A market participant can fulfil the reporting obligation himself or delegate it to a third party. Third

parties could be brokers, exchanges, automatic deal confirmation matching platforms, etc. While the

number of parties reporting to ACER should be kept within a certain range in the interest of an

efficient reporting process and delegation of the reporting obligation should be encouraged it is

advisable to impose certain minimum requirements upon all reporting parties. If market participants

report themselves they would qualify as a “Certified Self-Reporting Party”. Third parties offering such

service to another market participants would qualify as “Registered Reporting Mechanism”.

In order to operate as a Registered Reporting Mechanism (RRM), an organisation should

demonstrate:

Technical ability to report under the predefined REMIT format, therefore it must be capable

of reporting data in the data format, time limits, and frequency predefined in the

implementing acts; (RRM must have a system with a functioning interface for all relevant

parts of the REMIT standard);

Process ability to ensure that regularity of reporting is observed (Service Level Agreement in

place, team size to realistically implement such an SLA);

Long-term commitment to work as an RRM via financial and other size characteristics, in

order to follow through on commitments and make the needed investments and upgrade in

the future;

Investment in qualified personnel and demonstrated commitment to sustain a team of

professionals with the required credentials to undertake REMIT (RRM must have the “right

people”);

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For 3rd party providers: policies and safeguards in place to ensure safe handling of data (RRM

must be a trusted organisation.);

Appropriate mechanisms for authenticating the data source i.e. identification of the

beneficiaries and for ensuring data security and confidentiality as data reported is

economically sensitive (RRM must have the technical ability to ensure data security);

Can be regulated under EU law inside EU jurisdiction.

Incorporation of mechanisms for identifying and correcting errors in the reported data in

order to ensure efficient monitoring by ACER;

Establishment, implementation, and maintenance of an adequate disaster recovery plan

aiming at ensuring the maintenance of its functions, the timely recovery of operations, and

the fulfilment the reporting on behalf of their clients;

Public disclosure of the prices and fees associated with services provided.

A clear and neutral procedure for qualifying needs to be foreseen in implementation acts / observance

of ACER guidance. A 3rd party certification process would be the most appropriate.

TSOs may be considered as being naturally in the position to deliver scheduling/nominations data,

while the exemption of traders from delivering such data at the same time is recommended. As such

reporting obligation is asymmetric, TSO organisations should not be obliged to undergo a full

certification; however, they will need to have the technical capabilities in hand and should be certified

accordingly.

Recommendation:

Define criteria and a procedure on how to register centrally with ACER as “Certified

Self-Reporting Party” for market participants and as “Registered Reporting

Mechanism” as third-party service provider and accept reporting only from such

registered organizations; foresee an adjusted registration process for TSOs.

5.1.6. Reporting of fundamental data

Fundamental data is defined within Art. 8 (5) as “information related to the capacity and use of

facilities for the production, storage, consumption, or transmission of electricity or natural gas and

use of LNG facilities, including planned or unplanned unavailability of these facilities”. Such

information shall be reported centrally to ACER. The following considerations do not refer to the

already applicable obligation to publish insider information in Art.2(1)-

Gas

One of the key principles required by DG Energy in undertaking this work is that in order to keep

costs and the burden on market participants at a minimum, existing reporting and publication

channels should firstly be identified and assessed.

This section provides a view on fundamental data requirements in relation to gas TSOs (as they have

been a specific category with whom workshops have been undertaken as part of this project, as agreed

with DG Energy). At the end of this section we also provide a view on fundamental data reporting for

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gas storage and LNG data. It is assumed that fundamental data requirements in relation to gas

production will be, at least at an initial stage, fulfilled via the requirement of gas flows (via

nominations data) at entry points. However, further information requirements on gas production

could be considered at a subsequent stage.

Based on our discussions with the Commission, we have focused our analysis of the necessary

information on data collected by TSOs under Regulation (EC) 715/2009, as amended by Commission

Decision 2010/685/EU, amending Chapter 3 Annex I to the above mentioned Regulation. The context

of transparency requirements in relation to gas, including the data items to be published according to

transparency regulations, is outlined in more detail in previous sections.

In particular, whilst these transparency obligations are currently fulfilled by TSOs on an individual

basis, we understand that currently there are ongoing discussions at a European level in relation to

the potential introduction of requirements to publish transparency data via a central European

platform, likely to be some extension of the ENTSOG transparency platform. However, work in this

area has not commenced yet. We consider that, for practicality and cost reasons, the development of

harmonized transparency platforms should set the timeline for development of fundamental data

reporting by gas TSOs under REMIT.

It is important to highlight that transparency data currently published by TSOs is on an aggregate

basis by individual entry / exit / delivery point (not broken down to the level of individual market

participants).

It may also be appropriate to collect fundamental data (including data on capacity bookings) on a

disaggregated basis (i.e. by individual shipper), and to do so in a centralised manner via an extension

of existing transparency platforms. Such data can then be passed through to ARIS. However, it should

be noted that gas TSOs have expressed a number of concerns in relation to liability (e.g. which party is

liable for data held by TSOs) and data confidentiality (i.e. in relation to data submitted to a centralised

platform); any such centralised approach would therefore require sufficient clarity around

confidentiality and liability provisions to address these concerns.

As outlined in Section 4.5.2.10, there is ongoing harmonization work in the gas sector (including work

on development of ENTSOG’s Capacity Allocation Mechanism Network Code, Balancing Network

Code and Interoperability Network Code). Therefore for cost and practicality reasons, as well as in the

context of the principle of the avoidance of creation of unnecessary burdens or duplication of

reporting channels, we would recommend the introduction of an approach by which nominations data

is collected in the first instance (based on the data requirements outlined in the Draft Balancing

Network Code). This data includes:

Interconnection point identification;

Direction of contractual gas flow;

Network user identification or, if applicable, its portfolio identification;

Network user’s counterparty(-ies) identification or, if applicable, network user’s

counterparty(-ies) portfolio identification;

Start and end time for which the nomination is submitted;

The gas day D;

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The gas quantity to be transported.

The proposed approach for the collection of data on nominations is outlined earlier in this section.

Accordingly, for the purposes of this section, this is treated as trade/transportation contract data.

On the other hand, the collection of capacity allocation data and balancing data on an individual

shipper/trader level from TSOs should be introduced at a later stage, taking into account the further

harmonization of capacity mechanisms at a European level (i.e. following the publication of a final

version the ENTSOG codes mentioned above and their implementation at a national level), as well as

the potential introduction of a harmonised ENTSOG platform.

In the meanwhile, capacity allocations on a disaggregated basis could be monitored to some extent

(depending on the amount of data collected) with the capacity bookings data collected from

traders/shippers as well as from individual TSOs acting as data aggregators for this limited data.

Power

This section provides a view on fundamental data requirements in relation to electricity TSOs (as they

have been a specific category with whom workshops have been undertaken as part of this project, as

agreed with DG Energy).

Based on our discussions with the Commission, we have focused our analysis of the necessary

information on data collected by TSOs under Regulation (EC) 714/2009 and the ERGEG Advice on

Comitology Guidelines on Fundamental Electricity Data Transparency. The context of transparency

requirements in relation to electricity, including the data items to be published according to the

transparency regulation, is outlined in more detail in Sections 3.4.1 and 4.4.1.

Currently, TSOs comply with the transparency requirements by publishing the required data on their

individual websites. We understand that there is an ongoing discussion on a potential introduction of

requirements to publish such data on a central, pan-European platform, likely to be some extension of

the ENTSO-E transparency platform. We consider that for reasons of practicality and minimisation of

costs, the reporting requirements for electricity TSOs and the development of harmonised

transparency platforms should be synchronised time-wise.

It is important to highlight that transparency data currently published by TSOs is on an aggregate

basis, e.g. electricity load flows at cross border points (not broken down to the level of individual

market participants and single nominations). It is our understanding that the transparency data as

currently available (especially on individual TSO websites) contains fundamental data (as outlined in

previous sections) which largely fulfil the requirements of REMIT (Art. 8(5)).

Against this background, it may be appropriate to collect fundamental data (especially data on

capacity bookings) on a disaggregated basis. It would be possible to get disaggregated data using the

ENTSO-E's data formats (ESS and ECAN) relating to nomination and scheduling processes.

Furthermore, data could be published in a centralised manner via an extension of existing

transparency platforms; any such centralised approach would require sufficient clarity around

confidentiality and liability provisions.

As outlined in Section 3.4.1, there is ongoing harmonisation work in the electricity sector. This

especially includes ENTSO-E's data format standardisation and ENTSO-E's network code

development on the following areas:

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Capacity allocation and congestion management;

Requirements for generators;

Balancing;

Forward markets;

Demand connection;

Operational security;

Operational planning & scheduling;

Load frequency control & reserves.

Such harmonisation efforts should be taken into account when determining on the manner in which

transparency requirements under REMIT shall be met. Matters of efficiency and avoidance of cost

should be considered and lead to as much uniformity and centralisation as possible.

Recommendation:

Reporting of fundamental data should be undertaken via central transparency

platforms, to fulfil relevant transparency requirements. Collection of disaggregated

fundamental data should be undertaken via the same transparency platforms,

provided appropriate confidentiality and data ownership provisions are in place. In

the interim, collection of limited selected capacity information from market

participants should be via ARIS.

5.1.7. Uniform rules on the reporting of fundamental data

As outlined previously, power and gas TSOs do not necessarily see themselves as aggregators for any

data in addition to the data required under transparency requirements, and in particular they have

expressed a view that currently the requirement to report fundamental data on a disaggregated basis

(i.e. by shipper) is not clearly mentioned within REMIT. These issues should be addressed via the

drafting of the implementing acts.

Recommendation:

Clarify role of TSOs as data aggregators and the requirement to report disaggregated

fundamental data as part of drafting of implementing acts.

5.1.8. Timing and form for the reporting of fundamental data

Gas

The frequency of reporting fundamental data is to some degree dependent on the type of data

collected (for instance, yearly capacity allocations from auctions held once a year would not require

frequent reporting), therefore we would suggest the introduction of a requirement to report upon

change of data, with a maximum frequency of daily reporting (expected to be undertaken by end of

day). We would expect that the benefits of the introduction of within day reporting of capacity

bookings and nominations in terms of additional data availability would be outweighed by the costs,

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both for market participants terms of compliance and for ACER and the NRAs in terms of ability to

analyse this data.

Power

The time frames covered by the reported fundamental data and the respective due dates for the data

submissions vary depending on the type of data collected. The ERGEG Advice on Comitology

Guidelines for Fundamental Electricity Data Transparency sets forth a thoroughly structured data

matrix, ascribing to each data item which is to be reported, the respective time frame to which it is

related and the due date to which the data item is to be reported. Where applicable, a requirement to

update the data item is also included in the overall reporting requirement for the respective data item.

We would suggest reflecting the reporting frequency scheme laid out in the aforementioned ERGEG

Advice.

Recommendation:

Introduce a requirement to report fundamental data upon change, with a maximum

frequency of daily reporting.

5.1.9. Gas storage and LNG fundamental data

The definition of fundamental data outlined in Art. 8 (5) refers also to capacity and use of storage

facilities and use of LNG facilities. Transparency requirements in this area are outlined in Regulation

(EC) 715/2009, and include requirements to make available:

Information on the services offered and technical information;

Information on contracted and available storage and LNG facility capacities on a numerical

basis and on a regular and rolling basis;

Amount of gas in each storage and LNG facility and available storage and LNG facility

capacities, updated at least daily (Communicated also to the TSO, which shall make it public

on an aggregated basis). A request for confidential treatment of this data may be submitted by

storage operators to the NRA in cases in which a storage system user is the only user of a

storage facility.

A number of transparency requirements are also outlined in the Guidelines for Good TPA Practice for

Storage System Operators (GGPSSO) published in 2005 and amended in 2011.

Currently, the transparency requirements are fulfilled on an individual level by storage operators and

LNG facility operators by publishing data on their own websites.

The following harmonization initiatives have been undertaken on a voluntary basis:

A central transparency platform (“Aggregate Gas Storage Inventory”) is currently published

on Gas Infrastructure Europe (GIE)’s website, publishing gas storage inventory data on an

aggregate basis (by hub). The following data is published on a daily basis:

o Storage inventory level (current inventory level of gas in storage at 06:00, in mcm)

o Injection (storage increase at 06:00 compared to 06:00 on previous day, in mcm)

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o Percentage of maximum available storage in use

o Daily storage increase or decrease in %

o Data status (confirmed/estimated)

o Declared total maximum technical storage in mcm

o Declared total maximum technical injection / day in mcm

o Declared total maximum technical withdrawal / day in mcm

GLE (Gas LNG Europe) members have agreed to implement on a voluntary basis a common

transparency template to facilitate the access to this great amount of information. However,

their transparency obligations remain fulfilled at an individual level. The template includes

the following data:

o Contact details

o Terminal characteristics: Facilities main characteristics (e.g. nominal annual capacity,

regassification capacity, LNG storage capacity, number of LNG tanks), service

characteristics, LNG quality specification, gas quality conversion equipments

o Details on how to become a customer/user

o Capacities:

Primary market: allocation rules (CAM/CMP), available capacity (in

particular, data published in accordance with transparency requirements of

Reg. 715/2009 Art. 19.4)

Secondary market - allocation rules, available capacity, list of players, IT

platform, if available, for secondary market management

We recommend the extension of the requirements for publication of transparency data (although this

is likely to be outside the scope of REMIT), in order to enable a centralised collection of this

transparency information. The implementation of a centralised collection of fundamental data

(consistent with the transparency requirements) via TSOs relating to gas storage and LNG directly on

the ARIS database is likely to create a significant additional number of interfaces and impact on the

implementation costs. The centralised transparency platform could be used also as a means to collect

disaggregated data, provided that appropriate confidentiality and data ownership provisions are in

place.

Recommendation:

Reporting of fundamental data should be undertaken via central transparency

platforms to fulfil relevant transparency requirements. Collection of disaggregated

fundamental data should be undertaken via the same transparency platforms,

provided appropriate confidentiality and data ownership provisions are in place. In

the interim, collection of limited selected capacity information from market

participants should be via ARIS.

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5.2. Phased approach for reporting of trade data

In the following, a recommendation to a phased approach for implementing reporting under Article 8

REMIT is made. The definition of transaction types falling under “wholesale energy products” and the

scope of transactions to be reported should be clarified initially to provide sufficient clarity for market

participants as to the initial planning of implementation activities ensuring adherence. While on the

traders’ side the definition of standard products and the refining of reporting obligations are

sufficiently broad and thus not expected to be inapplicable in a few years time, the exact content of the

phasing and the time between phases may have to adapted based on actual implementation speed and

the needs for regulation arising out of market conditions. Regarding the reporting from TSOs, a

sufficient level of standardization for initial reporting of scheduling/nominations data will need to be

set. Therefore, we recommend that the phasing is put into the Implementing Act only in principle,

with the details left to ACER guidance.

ACER should always aim to give clear guidance on the current phase (i.e. in its first guidance on the

phase to be implemented, phase 1), and to provide the outline of the next phase (i.e. in its first

guidance, phase 2), together with a defined estimate of the time span before such next phase will be

implemented. Over the course of one phase, more precise guidance on the next phase can be issued

such that market participants have sufficient time to prepare their processes and systems to

implement it.

Care has to be taken that investments made following the obligations of a certain phase are not made

obsolescent through the introduction of the next phase. This can be achieved primarily by following

the principle of backward compatibility. In addition, the scope of reporting in subsequent phases

should be extended by whole process steps or trading venues, the idea being that a certain information

node (be it a market participant and their trading system, a market system or a scheduling system)

only needs costly changes at interfaces and the master data level once or at most twice.

From the perspective of a market participant, the current and next phase of REMIT reporting should

be reviewed, with a view of planning for changes needed in processes and systems over the next years.

This should be aligned with upgrades, migrations, mergers, and other major changes planned

independently, such that changes can be planned, implemented, and tested in clusters rather than

staggered out over time. Other reporting regimes such as EMIR, MiFID, and Dodd-Frank need to be

taken into account as well. Such planning should enable the market participant to have a schedule and

combination of possible major changes.

From the business and legal perspective of a trader, the portfolio of wholesale energy transactions has

to be reviewed in light of REMIT. The next step is the identification of those parts of the portfolio to be

reported in the long form and short form reporting regime. For both parts, make or buy decisions

have to be made. Phase 1 is intentionally designed such that market participants other than TSOs

should be enabled to delegate all of their long form reporting obligations to RRMs, provided the

exchanges, broker platforms, and matching services used by the market participant opt to qualify as

an RRM.

Following the focus of REMIT on the physical character of gas and power markets in the EU, it is

considered highly relevant to properly engage gas and power TSOs in a phase 1 reporting scheme. In

contrast to markets which focus on trading of financial products, gas and power markets are set up as

a combination of commodity transactions with logistical transactions ensuring availability of

transport (and in gas storage) capacity as a link between the commodity markets. As regards the

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implementation of REMIT reporting, this requires combining long form and short form reporting

from traders with adequate reporting of scheduling/nominations data from TSOs already in phase 1.

The following tables give an overview on how a phased approach could look like for the reporting of

trade data, summarizing the considerations taken in the chapter 5.

Table 14 Reporting of trade data – Phase 1

Reportingparty

Transaction Stage Long Form Reporting (LFR)/ short form Reporting(SFR)

Message Type under REMITReporting

Trader Order Stage Non applicable

Contract Stage LFR:At least “white list” (seechapter 5.1.3)

SFR:All other commoditytransactions

LFR:LongFormCommodityContract

SFR:ShortFormCommodityContract

Scheduling /Nomination Stage

Non applicable

Power TSO Order Stage Non applicable

Contract Stage Non applicable

Scheduling Stage Commodity:all nominations

Transport:all nominations

Comm., Transport:SchedulingNominationsPower

Gas TSO Order Stage Non applicable

Contract Stage Non applicable


Transport, Storage:non-existent

Comm., Transport, Storage:SchedulingNominationGas

Table 15 Reporting of trade data – Phase 2

Reportingparty

TransactionStage

Long Form Reporting(LFR) / short formReporting (SFR)

Message Type underREMIT Reporting

Trader Order Stage Only LFR:* Transactions on ElectronicBrokerage Platform* Transactions on regulated

Only LFR:CommodityOrder

SFR:

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exchanges non applicable

Contract Stage LFR:“white list” plus “grey list”

SFR: All other commodity,capacity, storage, LNGterminal

LFR:LongFormCommodityContract

SFR:ShortFormCommodityContract

Scheduling /Nomination Stage

Non applicable

Power TSO Order Stage Bidding following ECANprocess (“bid document”)

To be defined

Contract Stage Transparency platformformat

To be defined


Transport, Storage:all nominations

Comm., Transport:SchedulingNominationsPower

Gas TSO Order Stage Non applicable (nostandardized biddingprocess in place so far)

CapacityBiddingGas


To be defined


Transport, Storage:non-existent

Comm., Transport, Storage:SchedulingNominationGas

SSO, LSO Order Stage Non applicable


To be defined

Scheduling Stage Non applicable

Recommendation:

Follow a phased approach for the reporting of wholesale energy product transactions

to reflect the current amount of standardization in the market, taking into account the

economic impact of the implementation.

Indicate the duration of phase 1 (and of any further phases as may be required) as

being around two years. Sufficient clarity on the framework for subsequent phases

should be provided initially.

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As further clarity becomes available following the implementing acts, further non-

binding guidance can be provided to market participants

5.3. Phased approach for reporting of fundamental data

The table below summarises the proposed approach in relation to reporting of fundamental data,

outlining the reporting requirements for key players in this area, both on “day one” of implementation

of REMIT and in a later stage, following the potential implementation of central EU transparency

platform from ENTSO-E and ENTSOG. As outlined previously, it is considered appropriate that for

cost and practicality reasons, the development of harmonized transparency platforms at the EU level

should be delayed to ensure the development of fundamental data reporting by gas TSOs under

REMIT.

Table 16 Reporting of fundamental data – Phase 1

Reportingparty

Fundamental data reported Reporting channel

Power TSOs Transparency data reported on anational level published underRegulation (EC) 714/2009

Individual TSO websites, same as currentapproach. No link with ARIS envisaged.

Gas TSOs Transparency data reported on anational level published underChapter 3 of Annex I to Regulation(EC) 715/2009

Individual TSO websites, same as currentapproach. No link with ARIS envisaged.

Generators Transparency data reported on anational level published underRegulation (EC) 714/2009

Generation data published by TSOs onindividual TSO websites, plus requirementsto keep data at disposal of relevantauthorities

SSOs andLSOs

Transparency data to be madeavailable by individual operators asper Regulation 715/2009 andGuidelines for Good Practice forStorage

Individual websites, same as currentapproach

Producers No reporting obligation undercurrent transparency requirements.Could consider applying sameprinciples on storage.

Currently no data publication obligation

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Table 17 Reporting of fundamental data – Phase 2

Reportingparty

Fundamental data reported Reporting channel

Power TSOs Transparency data reportedpublished under Regulation (EC)714/2009 and data requirementsoutlined in ERGEG’s Advice onDraft Comitology Guidelines (andany other future regulation)

Central collection via ENTSO-ETransparency Platform

Gas TSOs Transparency data reportedpublished under Chapter 3 of AnnexI to Regulation (EC) 715/2009 (andany other future regulation)

Central collection via ENTSOG Transparencyplatform

Generators Generation data outlined inERGEG’s Advice on DraftComitology Guidelines

Central collection via ENTSO-ETransparency Platform (some collecteddirectly via platform, some collected viaTSOs)

SSOs andLSOs

Transparency data to be madeavailable by individual operators asper Regulation 715/2009 andGuidelines for Good Practice forStorage (and any other futureregulation)

Could consider introduction of centraltransparency platform.

Producers Could consider applying samereporting principles as storage forcontinental production

Data on EU production could be linked toSSO central transparency platform

Recommendation:

Reporting of fundamental data should follow existing and proposed regulations.

Develop harmonised transparency platforms to set the timeline for introduction of

fundamental data reporting. Consider introduction of central transparency

platforms for storage, LNG and EU production data.

Consistent with the approach outlined in the previous section define a clear timeline

for the introduction of Phase 2, which could estimated to be around 2 years. If central

collection of fundamental data is not introduced by TSOs (and other relevant market

participants as outlined above) within a defined timescale, introduce a REMIT

reporting obligation and format in order to collect fundamental data directly from

participants in ARIS as part of Phase 2.

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6. Concluding remarks

Our recommendations on reporting requirements for trade and fundamental data have covered thefollowing key areas:

Records of transactions

List of contracts and derivatives

Uniform rules on the reporting of transactions and orders to trade

Timing and form for the reporting of transactions and orders to trade

Reporting channels

Reporting of fundamental data

Uniform rules on the reporting of fundamental data

Timing and form for the reporting of fundamental data

Gas storage and LNG fundamental data

In addition, we have provided our views on the potential introduction of a phased approach toimplementation of such reporting requirements.

The recommendations outline a potential approach for reporting under REMIT, taking also intoaccount practicality considerations. For the avoidance of doubt: the proposed approach is notintended to limit in any way the scope of reporting obligations as outlined in REMIT.

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Appendix - Glossary

Agency for the Cooperation of Energy Regulators

ARIS ACER REMIT Information System

ARMs Approved Reporting Mechanisms

Art. Article

ATC Available _Transmission Capacity

BNetzA German Federal Network Agency

BRP Balance Responsible Parties

CAM Capacity Allocation Mechanism

CCP Central Counterparty

CMP Congestion Management Proposals

CEER Council of European Energy Regulators

CIM Common Information Model

CME Chicago Mercantile Exchange

CSV Comma Separated Value

D Day

Delfor Delivery Forecast message

DET dependent feed-in profile total

DG Energy Directorate-General for Energy

DLT dependent load profile total

DSO Distribution System Operator

EASEE-Gas European Association for the Streamlining of Energy Exchange - Gas

EC European Commission

ECAN ETSO Capacity Allocation and Nomination System

EDI Electronic Data Interchange

EEX European Energy Exchange

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EFET European Federation of Energy Traders

EFET eXRP EFET electronic eXchange Related Processes

e.g. for example

EIC Energy Identification Code

ENTSO-E European Network of Transmission System Operators for Electricity

ENTSOG European Network of Transmission System Operators for Gas

ERGEG European Regulators' Group for Electricity & Gas

ERRP ETSO Reserve Resource Process

ESMA European Securities Markets Authority

ESP ETSO Settlement and Reconciliation

ESS ETSO Scheduling System

etc. et cetera

ETRM Energy Trading and Risk Management

ETSO European Transmission System Operators (now ENTSO-E)

EU European Union

EURELECTRIC Union of the Electricity Industry

EUROPEX Association of European Energy Exchanges

FCT feed-in curve total

FSA Financial Services Authority

GCV Gross Calorific Value

GIE Gas Infrastructure Europe

GLE Gas LNG Europe

GTMA Grid Trade Master Agreement

GTS grid time series

H operational hour

ICE IntercontinentalExchange

ID Identifier

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IEC International Electrotechnical Commission

i.e. that is to say

ISDA International Swaps and Derivatives Association Inc.

ISIN International Securities Identifying Number

KWh kilowatt hour

LCT load curve total

LEI Legal Entity Identifier

LNG liquefied natural gas

LSO LNG System Operator

M month

MaBiS Market Rules for the Performance of Balancing Group Accounting in

Electricity

MADES Market Data Exchange Standard

mcm million cubic meters

MSCONS Metered Services Consumption report message

MTF Multilateral Trading Facility

MW megawatt

MWh megawatt hourm3(n) standard cubic meter

NRA national regulatory authority

NSR Non-Standard Reporting

NTC Net Transfer Capability

OTC over-the-counter

OTF Organized Trading Facility

PTDF Power Transfer Distribution Factor

PTR Physical Transmission Right

pwc PricewaterhouseCoopers

RRM Registered Reporting Mechanism

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SEF Swap Execution Facility

SET standard feed-in profile total

SLA Service Level Agreement

SLP standard load profiles

SR Standard Reporting

SSO Storage System Operator

T Trade Date

TC Technical Committee

TPC Transparency Platform Coordinator

TSO Transmission System Operator

UIOLI use-it-or-lose-it

U.K. United Kingdom

VAT value added tax

WG working group

XLS Excel spreadsheet

XML Extensible Markup Language

Y year

Current legislation:

ACER Regulation

Regulation (EC) No 713/2009 of the European Parliament and of the Council of 13 July 2009

establishing an Agency for the Cooperation of Energy Regulators

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:211:0001:0014:EN:PDF

Commission Decision 2010/685/EU

Commission Decision of 10 November 2010 amending Chapter 3 of Annex I to Regulation (EC) No

715/2009 of the European Parliament and of the Council on conditions for access to the natural gas

transmission networks


Electricity Directive

Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning

common rules for the internal market in electricity and repealing Directive 2003/54/EC

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Electricity Regulation

Regulation (EC) No 714/2009 of the European Parliament and of the Council of 13 July 2009 on

conditions for access to the network for cross-border exchanges in electricity and repealing Regulation

(EC) No 1228/2003


Gas Directive

Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning

common rules for the internal market in natural gas and repealing Directive 2003/55/EC

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2009:211:0094:0136:en:PDF

Gas Regulation

Regulation (EC) No 715/2009 of the European Parliament and of the Council of 13 July 2009 on

conditions for access to the natural gas transmission networks and repealing Regulation (EC) No

1775/2005


MAD

Directive 2003/6/EC of the European Parliament and of the Council of 28 January 2003 on insider

dealing and market manipulation (market abuse)

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32003L0006:DE:NOT

MiFID

Directive 2004/39/EC of the European Parliament and of the Council of 21 April 2004 on markets in

financial instruments amending Council Directives 85/611/EEC and Directive 2000/12/EC of the

European Parliament and of the Council and repealing Council Directive 93/22/EEC

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32004L0039:DE:NOT

Regulation (EC) No 1287/2006 implementing MiFID

Commission Regulation (EC) No 1287/2006 of 10 August 2006 implementing Directive 2004/39/EC

of the European Parliament and of the Council as regards recordkeeping obligations for investment

firms, transaction reporting, market transparency, admission of financial instruments to trading, and

defined terms for the purposes of that Directive

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32006R1287:EN:NOT

REMIT

Regulation (EU) No 1227/2011 of the European Parliament and of the Council of 25 October 2011 on

wholesale energy market integrity and transparency

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=CELEX:32011R1227:EN:NOT

Proposed legislation:

CSMAD

Directive of the European Parliament and of the Council on criminal sanctions for insider dealing and

market manipulation (20.10.2011)

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=COM:2011:0654:FIN:EN:PDF

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EMIR

Regulation of the European Parliament and of the Council on OTC derivatives, central counterparties

and trade repositories (19.03.2012)

http://register.consilium.europa.eu/pdf/en/12/st07/st07509-re01.en12.pdf

MAR

Regulation of the European Parliament and of the Council on insider dealing and market

manipulation (market abuse) (20.10.2011)


MiFID II

Directive of the European Parliament and of the Council on markets in financial instruments

repealing Directive 2004/39/EC of the European Parliament and of the Council (20.10.2011)


MiFIR

Regulation of the European Parliament and of the Council on markets in financial instruments and

amending Regulation [EMIR] on OTC derivatives, central counterparties and trade repositories

(20.10.2011)


Other Sources:

Agency for the Cooperation of Energy Regulators (ACER): Draft Framework guidelines on

Interoperability and Data Exchange Rules for European Gas Transmission Networks, for public

consultation (FGI-2012-G-003), 16 March 2012,

http://www.gaslink.ie/files/Copy%20of%20library/20120321115604_Draft%20FG%20Interoperabili

ty%20Marc.pdf

Council of European Energy Regulators (CEER): Amendment of the Guidelines of Good Practice for

Third Party Access (TPA) for Storage System Operators (GGPSSO), Guidelines for CAM and CMP,

July 2011http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Gas/Tab/C11-GST-15-03_amdt%20GGPSSO%20on%20CAM%20and%20CMP_14-July-2011.pdf

Council of European Energy Regulators (CEER): Draft Vision for a European Gas Target Model, ACEER Public Consultation Paper (C11-GWG-77-03), 5 July 2011,http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20PUBLIC%20CONSULTATIONS/GAS/Gas_Target_Model/CD/C11-GWG-77-03%20GTM%20PC_5-July-2011.pdf

ESS Implementation Guidelines:https://www.entsoe.eu/fileadmin/user_upload/edi/library/schedulev3r3/documentation/ess-guide-v3r3.pdf

European Association for the Streamlining of Energy Exchange-Gas (EASEE-Gas): Common BusinessPractice (EDIG@S Protocol 2003-003/02), 7 November 2007,http://easee-gas.eu/docs/cbp/approved/CBP2003-003-02_7Nov07.pdf

European Network of Transmission System Operators for Electricity (ENTSO-E): MADESCommunication Standard, November 2011,https://www.entsoe.eu/fileadmin/user_upload/edi/library/mades/mades-v1r0.pdf

118

European Network of Transmission System Operators for Gas (ENTSOG): Network Code on CapacityAllocation Mechanism (CAP 0210-12), 6 March 2012,http://www.entsog.eu/publications/camnetworkcode.html

European Network of Transmission System Operators for Gas (ENTSOG): Draft Code on GasBalancing in Transmission Systems (BAL300-12), 12 April 2012,http://www.gaslink.ie/files/Copy%20of%20library/20120423094253_Draft%20Code%20on%20Gas%20Balancing%20in.pdf

European Regulators' Group for Electricity & Gas (ERGEG): Advice on Comitology Guidelines onFundamental Electricity Data Transparency (E10-ENM-27-03), December 2010http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_CONSULT/CLOSED%20PUBLIC%20CONSULTATIONS/ELECTRICITY/Comitology%20Guideline%20Electricity%20Transparency/CD/E10-ENM-27-03_FEDT_7-Dec-2010.pdf

International Swaps and Derivatives Association Inc. (ISDA): Commodities Trade Processing LifecycleEvents White Paper, April 2012http://www2.isda.org/functional-areas/research/studies/

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Appendix - REMIT ReportingDocument Format

As a policy, recommended REMIT report formats should be selected based on the following criteria:

- Publicly available documentation,

- In use by a significant share of REMIT-related roles,

- European scope,

- XML formats are preferred since a higher level of syntactic format constraints applies here.The possible disadvantage of a redundant format overhead vs., e.g., EDIFACT or CSV formatsis weight out by the possibility to compress XML when stored in the ARIS document store.

- If there is more than one format available that meet the above criteria one of them should beselected that allows accommodate data of the remaining formats such that the number ofreport formats per transaction category can be limited to one.

The following list of document types for reporting applies to phase 1, i.e., to the followingMessageTypes:

- CommodityContract (Long Form and Short Form)

- SchedulingNominationPower

- SchedulingNominationGas

OTC trade data format for reporting of CommodityContracts

Generally, the following channels exist partly with available document formats for reporting:

- CPML standard report format (Commodity Products Markup Language, see

www.cpml.eu). This format is based on the EFET eCM process (electronic Confirmation

Matching) and is in use since the year 2004 by ca. 65 trading organizations and brokers. It is

also in production use for reporting under Dodd-Frank since January 2012 for reporting of

US-based OTC trades. A high share of trades executed bilaterally or on broker platforms are

confirmed between energy traders based on the CpML standard.

- FPML (Financial Products Markup Language). This format is commonly in use in the US and

partly by European investment banks. Its focus is on financial products while energy-specific

features such as delivery schedules, delivery types, units of measures etc. are not represented.

- Data output from broker platforms. Information on XML document formats for broker

platforms is not available as a sector-wide standard across broker platforms which unifies

CommodityContract reporting across energy exchanges. Specific platforms provide APIs

allowing users to retrieve information on trading organisations, accounts, orders, trades,

instruments etc. In order to support a unified report format, an extraction logic is often

required that transforms results of API queries into a document format that contains the

entire trade data.

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- Data output from exchanges. No standard format exists here that is shared across

European energy exchanges. The main requirement is here to use a flexible and extensible

format that can accommodate trade data reported by exchanges. “Any future format should be

flexible and easily accessible” (from the Europex reply).

Since OTC CommodityContract formats are more detailed by nature, we followed the approach to usesuch a format as the canonical format for reporting CommodityContracts from exchanges, brokerplatforms, OTC traders, and clearing services. The CPML format is the candidate which comes closestto this requirement, specifically when extended by its report envelope that is already in use forreporting under Dodd-Frank. We will, therefore, describe in the following the CPML structure andprovide additional mapping information for broker platforms and exchanges.

CpML can be extended for REMIT reporting by additional XML elements that accommodate specificregulatory information (e.g., venue information, a report identifier, etc.). This applies to regulatoryrequirements under Dodd-Frank and REMIT. It can also be expected that later-on also EMIR-specificdata will be encapsulated in an according document section.

The following figure shows the structure of the CPML trade confirmation format for tradeconfirmations which is a candidate for trade reporting by traders, broker platforms, exchanges, andclearing services. Optional, conditional, or repetition of XML sections and data types used for XMLelements are specified in the CPML standard which is – in turn – based on the EFET eCM4.1standard.

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Figure: OTC trade data in CPML format

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As an extension for regulatory reporting, CPML foresees a reporting envelope wrapping the abovedescribed trade confirmation document schema. The envelope holds additional data required by thedifferent reporting regimes. The most advanced information is available for Dodd-Frank (live sinceJanuary 2012), a REMIT section is already foreseen for future extension.

Figure: CpML Reporting Data

The REMITInfo XML Section can be further extended to accommodate specific additional reportinformation in extension of CPML trade confirmation data.

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Figure: CpML Reporting Data

Under EFET, a reporting-related standardisation group has been formed that is co-chaired by FilipSleeuwagen (EFET) and Cemil Altin (EDF Trading). Its focus is on optimising report data for thedifferent regulatory regimes. It is expected that the Cpml reporting header and its REMITInfo sectionwill be adjusted as specific requirements come up over the second half of 2012.

Trade Data Mapping from Exchanges, Broker Platforms, and Clearing ServicesThe following table describes the mapping how the report output from

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- Exchanges,- broker platforms, and- OTC clearing services

is mapped to the CPML reporting format for CommodityContracts. The entire report data isdistributed across two parts,

1. the ReportingHeader as it is defined by EFET,2. the REMITInfo section, and3. the main document part which is equal to an OTC trade confirmation.

In the following, ACERIDs are used as an abstraction for a single code schema used under REMIT forthe identification of market participants. It has to be agreed if EIC codes, LEIs or it may be an ACER-specific code.

1. StandardCommodityContract, Reporting Header

XML Element Values to be mapped by Market Participants, Exchanges,Broker Platforms, or Clearing Services

SchemaVersion Use value “1”

SchemaRelease Use value “0”

EnvelopeID Use a unique ID for the envelope.

SenderID Use ACERID of market participant/RRM

ReceiverID Use ACERID of ACER system.

CreationTimestamp Date and time of the creation of the envelope (UTC time, ISO 8601

format).

ReportingRegimes This section holds specific reporting metadata the goes beyond thereport content in the embedded OTC trade confirmation data.

ReportingRegimes/DFInfo Report metadata specific for reporting under Dodd-Frank, notrelevant for reporting under REMIT

ReportingRegimes/REMITInfo Data specific for reporting under REMIT

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2. REMITtInfo Section

XML Element Values to be mapped by Exchanges, Broker Platforms, orClearing Services

Status Status of the contract, allowed values are: “Unconfirmed”,“Confirmed”, “Cleared”, “Amendment”, “Cancelled”

Exchanges: use “Confirmed” or “Cleared”

broker platforms: use “Unconfirmed” or “Confirmed”bilateral trades: Use “Unconfirmed” or “Confirmed”

TradeID This value must be unique per TradeIDIssuer

Exchanges and broker platforms as RRM: use execution systemtrade ID here

Clearing services as RRM: use trade ID of the execution system.

TradeIDIssuer ACERID of the entity that has created the TradeID. This is either anexchange, a broker platform or a clearing service.

ExecutionVenue Acer ID of the execution platform (exchange or broker platform),e.g., PowerNext, or Globalvision. This list is maintained as a list byACER.

ExecutionDateTime Date and time of the execution (UTC time, ISO 8601 format).Condition: use date & time in case of exchange or broker platformas venue.

Bilateral trades: Use trading system timestamp

VenueType One of the following: “Exchange”, “BrokerPlatform”, “Voice”,“Bilateral”. The actual broker is given in the “Agents” section of theTradeConfirmation.

VenueProductID Proprietary product code of the execution venue. Delivery periodinformation is not required as part of the product code. Examplesare: “F0BM” (EEX), “DBF Aug-13” (ENDEX codes), “TD5 OCT10C120” (NOS).

ContractNature Use one of the following: “Commodity”, “Transport”, “Storage”,“Balancing”.Derive the value from the product definition.

DeliveryType Either “Financial” or “Physical”

Derive the value from the product definition.

ContractType This element exists already in the TradeConfirmation as“LoadType” section but is not used for confirmation purposes. Fortrade classification under REMIT it makes sense to use one of thefollowing values: “Base”, “Peak”, “OffPeak”, “Custom”, “Other”.

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XML Element Values to be mapped by Exchanges, Broker Platforms, orClearing Services

Derive the value from the product definition

DeliveryPeriodType One of the following: “Hour”, “Day”, “Weekday”, “Weekend”,“Month”, “Quarter”, “Season”, “Year”.

Derive the value from the product definition

Lots Put number of traded lots here. In case of OTC trades, use “1”.

ClearingVenue Acer ID of the clearing service (this is either a clearing house or anagency that acts as a market interface for the registration forclearing).

Conditional: Use if trade is cleared

ClearingID Conditional: Use if trade is cleared

ClearingTimeStamp Date and time of clearing for this trade (UTC time, ISO 8601 format).


ClearingProductID Proprietary product code of the clearing venue.


BuyerTradeID Optional: if available report the local TradeID of the buyer’s tradingsystem

SellerTradeID Optional: if available report the local TradeID of the seller’s tradingsystem

BuyerUserID Put venue user ID of the buyer here, e.g., Acer code for traderesponsible.

Conditional: if unilaterally reported, only required for the buyer roleotherwise required.

SellerUserID Put venue user ID of the seller hereConditional: if unilaterally reported, only required for the seller roleotherwise required.

AdditionalData This is an optional, repeatable section which accommodates furtherreport information that individual reporting entities are willing toprovide.

AdditionalData/Name Field name of type “string”.

AdditionalData/Value Data value of type “string”.

3. StandardCommodityContract, TradeConfirmation section

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Only deviations from the OTC use of the section “TradeConfirmations” are described here. Please referto the CPML definition for further details.


DocumentID See EFET eCM rules

DocumentUsage “Test” or “Live”

SenderID ACERID of the server

ReceiverID Use ACERID of ARIS

ReceiverRole “REMIT”

DocumentVersion Start with 1. In case on amendments (phase 2) increase by 1

Market See element definition in CPML

Commodity Derive from venue product definition. Only submit reports for“power” or “gas”

TransactionType See element definition in CPML

DeliveryPointArea For trades with physical settlement, use EIC code of delivwry pointotherwise use EIC code for market area.

BuyerParty ACERID of buyer

SellerParty ACERID of seller

LoadType Derive from venue product definition. Use “base”, “peak”, “off-peak”, or “other”

Agreement Venues should use “MA” for member agreement

Currency Derive from venue product definition. Use ISO code.

TotalVolume Calculate #lots X #load hours for the delivery period.

TotalVolumeUnit Mapping should be normalised to MWh.

TradeDate Put execution date here

CapacityUnit Not used

PriceUnit/Currency Derive from venue product definition. Use ISO code.

PriceUnit/Currency/UseFractionUnit

PrictUnit/CapacityUnit Should be only MW, mapping must normalize if necessary

TimeIntervalQuantities Repeat “TimeIntervalQuantity” for each individual delivery.

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TimeIntervalQuantity/DeliveryStartDateAndTime

Timestamp, derive from product definition

TimeIntervalQuantity/DeliveryEndDateAndTime

Timestamp, derive from product definition

TimeIntervalQuantity/ContractCapacity

= #lots if MW/lot = 1

TimeIntervalQuantity/Price = price per delivery time interval if this is individual

FixedPriceInformation See usage rules in the CPML standard

FixedPriceInformation/FixedPRicePayer

ACERID, see CPML specification, derive value from venue’s productdefinition

TotalContractValue = #lots * contract value per lot * number of time units

FloatPriceInformation See usage rules in the CPML standard

FloatPriceInformation/FloatPricePayer

ACERID

FloatPriceInformation Used for swaps float leg details, see CPML specificationValues for commodity references have to be derived from thevenue’s product definition.

Rounding,CommonPricing,OrderNumber,EffectiveDate,TerminationDate,EUATradeDetails,PhysicalCoalTradeDetails,HubCodificationInformation,Account&ChargeInformation,DeliveryPeriods

Do not use these elements by exchanges, broker platforms, clearingservices.

Option Data Option section is optional. Only data items required for reportingare listed here

OptionType Derive from venue product definition, either “put” or “call”

OptionWriter ACERID of the Seller party

OptionHolder ACERID of the Buyer party

OptionStyle Derive from venue product, either “European” or “American”

StrikePrice Derive from venue product definition.

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PremiumCurrency Derive from venue product definition.

TotalPremiumValue Derive from venue product definition.

Swaps Data Swap leg details are repeated under “FloatPriceInformation”, followthe EFET population rules for swaps data.

FloatPricePayer Derive from venue product definition.

CommodityReferencePrice Derive from venue product definition.

IndexCommodity Derive from venue product definition.

IndexCurrencyUnit Derive from venue product definition.

IndexCapacityUnit Derive from venue product definition.

SpecifierPrice Derive from venue product definition.

Factor Derive from venue product definition.

DeliveryDate Derive from venue product definition.

Agents/…/BrokerID Exchanges: Do not useBroker platform: Put ACERID of broker here

Futher optional root-level data

TradeTime Execution Time

TraderName Mot mandatory for reporting since REMIT reporting headerelements hold this information.

Trade Lifecycle events: Amendments (Phase 2)

An amendment to a commodity contract is submitted with the same DocumentID but an increasedversion number. It replaces the previous version which is not used anymore for calculations and datacomparisons. However, updated versions of data should remain in the system to allow for doing ahistoric analysis.

The Status element within the REMITInfo section of the CPMLReportingEnvelope has to be set to“Amended”.

Trade Lifecycle events: Cancellations (Phase 2)

Market participants or RRMs may cancel reported data out of the ARIS system. This leads to the effectthat trade data is not used for calculation anymore but still remains in the system for historic analysis.

The Status element within the REMITInfo section of the CPMLReportingEnvelope has to be set to“Amended”.

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The CPML Cancellation document type is recommended here:

Figure: CPML Cancellation XML schema

REMIT Business Acknowledgement

Apart from a technical acknowledgement which confirms reception and storage of the document for areport by ACER, the BusinessAcknowlegement confirms successful processing of the data received.This includes e.g., verification of codes, application of validation rules and successful storage of thereport data in the operational database tables.

The REMIT Business Acknowledgement takes pattern from the CPMLformat:

Figure: REMIT BusinessAcknowledgement

XML Element

SchemaVersion This is set to “1”

SchemaRelease This is set to “0”

DocumentID A unique ID within the ACER database

Sender ACERID of ACER

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Receiver ACERID of the sender of the report document

ReceiverRole Use: “ReportingEntity”

ReferencedDocumentID Document ID of the received report

ReferencedDocumentVersion Version ID of the received report

Figure: REMIT Business Acknowledgement

REMIT Rejection

If report data is invalid (syntactically or semantically), a Rejection document is sent back to thereporting entity.

XML Element

SchemaVersion This is set to “1”

SchemaRelease This is set to “0”

DocumentID A unique ID within the ACER database

Sender ACERID of ACER

Receiver ACERID of the sender of the report document

ReceiverRole Use: “ReportingEntity”

ReferencedDocumentID Document ID of the received report

ReferencedDocumentVersion Version ID of the received report

Reason Mandatory, repeatable section

Reason/ReasonCode A list of rejection codes needs to be defined. As many validation

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XML Element

error as possible should be codified

Reason/ErrorSource Location of the receiving system where the error was detected, e.g.,XML validation or business validation

Reason/Originator Business entity that caused the rejection

Reason/ReasonText Additional explanation of the reason for the rejection

Figure: REMIT Rejection

Short-Form Reporting of Commodity Contracts

Non-Standard CommodityContracts are reported in a dedicated format which allows to provide coretrade information as a repeated list.

Non-standard Trade ReportIssuer RWE Supply & Trading Report Date 31.07.2013

Issuer ACER Code ABC_RWEST_1234_BlaBla

# Venue Buyer Seller TradeID Broker Comm DelType Date Volume Unit/Load Delivery to Contr Value Curr /UoM Del Period

1 OTC ABC_RWEST_1234_BlaBla ABC_EDFT_4711_xyz RWE_4711 Power Financial 02.07.2013 1.000.000 MWh DEL_50HERTZ 40 EUR MWh 01.01.14-31.12.14

2 OTC ABC_RWEST_1234_BlaBla ABC_CITI_9999_abc RWE_4712 CDE_GFI_xxx Power Physical 04.07.2013 2.000.000 MWh DEL_50HERTZ 45 EUR MWh 01.01.14-31.01.14

3 OTC ABC_SW_HUBENDUEBEL ABC_RWEST_1234 RWE_4713 Power Physical 05.07.2013 3.000.000 MWh DEL_RTE 45 EUR MWh 01.02.14-28.02.14

4 OTC ABC_SW_DDORF_xxx ABC_RWEST_1234 RWE_4714 Power Financial 08.07.2013 4.000.000 MWh DEL_AMPRION 46 EUR MWh 01.01.14-31.12.14

5 OTC ABC_RWEST_1234_BlaBla ABC_EON_4711 RWE_4715 CDE_ICA_xxx Power Financial 09.07.2013 5.000.000 MWh DEL_AMPRION 47 EUR MWh 01.01.14-31.03.14

6 OTC ABC_EON_xxx ABC_RWEST_1234 RWE_4716 Power Financial 11.07.2013 6.000.000 MWh DEL_AMPRION 47 EUR MWh 01.04.14-30.06.14

7 OTC ABC_RWEST_1234_BlaBla ABC_EDFT_4711_xyz RWE_4717 CDE_SPT_xxx Power Physical 12.07.2013 7.000.000 MWh DEL_50HERTZ 47 EUR MWh 01.01.14-31.12.14

8 OTC ABC_EON_xxx ABC_RWEST_1234 RWE_4718 CDE_TPB_xxx Power Financial 12.07.2013 8.000.000 MWh DEL_AMPRION 48 EUR MWh 01.02.14-28.02.14

9 OTC ABC_SW_HUBENDUEBEL ABC_RWEST_1234 RWE_4719 Power Financial 15.07.2013 9.000.000 MWh DEL_50HERTZ 49 EUR MWh 01.01.14-31.03.14

10 OTC ABC_CITI_9999_abc ABC_RWEST_1234 RWE_4720 Power Physical 16.07.2013 10.000.000 MWh DEL_RTE 49 EUR MWh 01.04.14-30.06.14

<<< Prev. Page Next Page >>>

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Figure: Excel entry sheet for Short Form reporting

The data fields for Short Form Reporting are:

Field Name

ReportingEntity ACERID of the issuer of a short form report

ReportDate Date type of report creation, ISO 8601 format.

ReportPeriod Should be a month, use start data and end date

TradeData Mandatory, repeatable

Venue Use ACERID of the venue, use “OTC” in case of OTC trades

Buyer User ACERID of buyer

Seller Use ACERID of seller

TradeID Use trade ID of venue or in case of unbrokered OTC trades, uselocal trade ID of the local trading system

Broker ACERID of the broker

Commodity Either “Power” or “Gas”

DeliveryType “Physical” or “Financial”

TransactionTypeDescr Free text to describe transaction type

TransactionDate UTC DateTime value

Volume Use an estimation of the total volume. The calculation follows theone for the TotalVolume element

VolumeUnit Should be MWh for power or “kWh/d” for Gas

DeliveryPointArea EIC code for the delivery point or market area

ContractValue Total value of the contract, possibly only estimated

ContractValueCurrency Should be “EUR”

ContractValueCurrencyRate FX vs. EUC rate at the time of the contract ifContractValueCurrency is not EUR

ContractValueUoM Should be “MWh”for power or “kWh/d” for Gas

DeliveryPeriod Start and end of the deliveryPeriod

Phase 1 Reporting by Power TSOs

For phase 1, only the message type ScheduleNominationPower information is required. Schedule datashould be reported based on the most exact document that is exchanged between traders and TSOs.

Since scheduling is a process that starts on Dthe last schedule for the last intraday time interval holds to most precise information.

The Scheduling process also foresees that TSO validate submitted data (against other traders andTSOs). If schedules received by TSOs are balanced, they confirm this by sending aConfirmationReport back to each trader. This is exactly the document type that should also be usedfor reporting under REMIT.

Therefore it is expected that reporting takes place after the last time interval of delivery day D hasbeen scheduled. Moreover, for all earlier time intervals of D the actually scheduled load has to bereported in the ScheduleNominationPower document.

The following figure shows the scheduling process as defined in the ESS Implementation Guide(https://www.entsoe.eu/fileadmin/user_upload/edi/library/schedulev3r3/documentation/essv3r3.pdf):

Figure: ESS scheduling process

Following the ESS documentation, the Confirmaconsisting of the following sections:

- ConfirmationReport header (here messaging information, parties, and further identificationsare located),

- a repeatable ImposedTimeSeries section (delivery point informationfurther details on the type of delivery)

- period data: This data has to be normalised to a period of one day with hourly intervals forreporting to ARIS.

- Interval data: These are 24 hourly load values.

Since scheduling is a process that starts on D-1 with a sequence of possible intraday adjustments, onlye for the last intraday time interval holds to most precise information.

The Scheduling process also foresees that TSO validate submitted data (against other traders andTSOs). If schedules received by TSOs are balanced, they confirm this by sending a

back to each trader. This is exactly the document type that should also be used

Therefore it is expected that reporting takes place after the last time interval of delivery day D hasall earlier time intervals of D the actually scheduled load has to be

reported in the ScheduleNominationPower document.

The following figure shows the scheduling process as defined in the ESS Implementation Guidehttps://www.entsoe.eu/fileadmin/user_upload/edi/library/schedulev3r3/documentation/ess

Figure: ESS scheduling process

documentation, the Confirmation Report uses a hierarchical data schema,consisting of the following sections:

ConfirmationReport header (here messaging information, parties, and further identifications

a repeatable ImposedTimeSeries section (delivery point information is located here andfurther details on the type of delivery)period data: This data has to be normalised to a period of one day with hourly intervals for

Interval data: These are 24 hourly load values.

134

1 with a sequence of possible intraday adjustments, onlye for the last intraday time interval holds to most precise information.

The Scheduling process also foresees that TSO validate submitted data (against other traders andTSOs). If schedules received by TSOs are balanced, they confirm this by sending a

back to each trader. This is exactly the document type that should also be used

Therefore it is expected that reporting takes place after the last time interval of delivery day D hasall earlier time intervals of D the actually scheduled load has to be

The following figure shows the scheduling process as defined in the ESS Implementation Guidehttps://www.entsoe.eu/fileadmin/user_upload/edi/library/schedulev3r3/documentation/ess-guide-

tion Report uses a hierarchical data schema,

ConfirmationReport header (here messaging information, parties, and further identifications

is located here and

period data: This data has to be normalised to a period of one day with hourly intervals for

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Figure: ESS Confirmation Report Document Schema

Out of an ESS ConfirmationReport document, the following ARIS ScheduleNominationPower tablesare populated. Not all data elements need to be used for reporting (these are omitted).

ConfirmationReportXML Element

Mandatory,Optional,Cond. /Data type

Description

ConfirmationReport Header

MessageIdentification M

c35

Must be unique per TSO

MessageType M

enum

The confirmation report document type identifies the

information flow characteristics.

MessageDateTime M

DateTime

Use UTC time here

SenderIdentification M

ACERID

The TSO’s EIC code. Practically, the document may be

reported through an RRM, e.g., a transparency platform.

ReceiverIdentififcation M

ACERID

The EIC code of the trader goes here.

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Description

ScheduleTimeInterval M

DateTime

Beginning and end of the delivery period.

The start and end date and time must respect the format:

YYYY-MM-DDTHH:MMZ/YYYY-MM-DDTHH:MMZ.

The time must be expressed as UTC time in ISO 8601

format.

Domain C

C18

See ESS Code list definition

SubjectParty C The party that is the subject of the being confirmed.

SubjectRole C

ProcessType The nature of the process defined in the document being

confirmed.

TimeSeriesConfirmation Section

BusinessType The nature of the time series for which the product is

handled.

Product M

C3

Identification of an energy product such as Power, energy,reactive power, transport capacity, etc.

ObjectAggregation M

C3

Identifies how the object is aggregated.

InArea O

ch18

Area to which a delivery is directed, EIC code

OutArea O

Ch18

Area from which a delivery is provided, EIC code

InParty O

C16

The EIC of the Party to which a delivery is made

OutParty O

C16

The EIC of the Party who delivers

CapacityContractType C

C3

The contract type defines the conditions under which thecapacity was allocated and handled. e.g.: daily auction,weekly auction, monthly auction, yearly auction, etc.

The significance of this type is dependent on the in area andout area specific coded working methods. The transmissioncapacity allocator responsible for the area in questionauctions defines the contract type to be used.

CapacityAgeement C

C35

The identification of an agreement for the allocation ofcapacity to a party.

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Description

Measurement M

C3

The unit of measure which is applied to the quantities inwhich the time series is expressed.

Period

TimeInterval TimeIntervalType

Resolution Hourly

Interval

Pos Int Running number, should be from 0 to 23 for the hours of aday.

Qty Int The scheduled quantity for a given hour

Phase 1 Reporting by Gas TSOs

For Gas nominations, the EDIG@S standard is proposed. It is important to highlight that the currentuse of EDIG@S is not sufficiently standardised across Europe. I.e., document semantics may varyfrom country to country.

In order to received the most precise nomination document for a given delivery day D (gas day), it isexpected that gas TSOs use their NOM.RES document which is issued within the EDIG@S nominationprocess as the response document sent back to traders after having received NOM.INT (nominationdocuments) from both traders and after having balanced them.

Also as part of the gas nomination process, several nomination processes may be carried out bymarket participants. In this case the last possible nomination (possibly intraday) should be taken asthe basis for reporting.

138

Figure: The EDIG@S NOMRES message should be used for REMIT Reporting

Following the EDIG@S documentation, the NOMRES uses a hierarchical data schema, consisting ofthe following sections:

- NominationResponse header (here messaging information, parties, and furtheridentifications are located),

- a repeatable ConnectionPointInformation section (connection point information is locatedhere and further details on the shipper (= trader))

- period data: This data has to be normalised to a period of one day with hourly intervals forreporting to ARIS.

March 2012Stakeholder Workshop NRAsSlide 28

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Figure: EDIG@S NOMRES Document Schema

As identification of sender and receiver of a NOMRES has to be retained in order to obtain codes ofTSO and shipper, the actual sender of the document (RRM, e.g., gas transparency platform) and theACER as the receiver have to be identified as a part of the messaging envelope.

The following NOMRES fields may be used for reporting:

NOMRES Field Mandatory,Optional,Cond. /Data type

Description

Nomination Response

Identification M

c30

This is based on the Identification field in NOMRES. Must be

unique per TSO

Type M

int

Should be a confirmation notice (originally sent to shipper) or an

exchange confirmation notice

CreationDateTime M

DateTime

The date and time that the document was prepared for

transmission by the application of the initiator (ISO 8601 format).

ValidityPeriod M Start and end date and time of the period of validity of the

document.

ContractReference M

C35

Contract identification or contract group identification

ContractType Indicates if ContractReference is either a contract number or a

contract group.

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Description

IssuerIdentification M

EIC Code

The identification (EIC code) of the TSO that has originally sent the

NOMRES document to the shipper

ReceipientIdentififcation M

EIC Code

The identififcation of the shipper / trader.

ConnectionPoint Information

Section

Mandatory & repeatable within the root section

Status M

C3

Status = “16G” (Confirmed) should be used here.

SubContractReference C

C35

The subcontract reference identifies the contract identification that

is relevant for the connection point.

Category C

C3

Type of yearly take-off

ConnectionPoint M

EIC Code

EIC Code for the connection point

AccountIdentification M

C35

The identification of an Account that is known to both systemOperators.

AccountRole M

C3

The following Roles are permitted: UD = Utlimate Customer ZES =External Shipper

Period Mandatory & repeatable

TimeInterval M

varchar100

Beginning and end of the delivery, should be a whole gas day of 24

hours.

Direction M

ch2

This identifies the direction of the energy flow. Intended codes are:Z02 = Input Z03 = Output

Quantity M The quantity for the connection point within the time interval inquestion.

MeasureUnit M The unit of measurement used for all the quantities expressedwithin a time series. The following are the codes recommended foruse:

- KW1 Kilowatt-hour per hour (kWh/h)- KW2 Kilowatt-hour per day (kWh/d)- HM1 Million cubic meters per hour- HM2 Million cubic meters per day- TQH Thousand cubic meters per hour- TQD Thousand cubic meters per day- MQ5 Normal cubic meters- P1 Percentage (only where Type = 20G).

Should be normalised to MWh/h = MW.

141


Description

Status Optional, used if additional business information is added to thePeriod section.

QuantityStatus M,

C3

This information provides the status of the quantity for the timeinterval being reported. Currently only one of the following statusvalues are permitted:

- 06G = Mismatch.- 07G = Interrupted.- 08G = Interrupted firm.- 09G = Quality deficient.- 10G = Reduced capacity.- 11G = Below 100%.- 12G = Settled.- 13G = Unchanged settled.- 14G = No counter nomination.- 35G = Counter Party Prevailed.- 36G = No Match counter party prevailed.- 37G = Reduced Nominated Quantity.

ReasonText C,

Varchar512

If the code does not provide all the information to clearly identifythe justification of an amendment then the textual information maybe provided.

This report has been prepared for and only for

n. 2011/ETU/ENER/B2/2011-533/SI2.613513 dated 19/12/2011 under Service Framework Contract

n. TREN/R1/350-2008 and for no other purpose. We do not accept or assume any liability or duty

of care for any other purpose or to any other person to whom this report i

hands it may come save where expressly agreed by our prior consent in writing.

© 2012 PricewaterhouseCoopers. All rights reserved. "PricewaterhouseCoopers" and "PwC" refer to

the network of member firms of PricewaterhouseCoopers Inte

member firm is a separate legal entity and does not act as agent of PwCIL or any other member firm.

PwCIL does not provide any services to clients. PwCIL is not responsible or liable for the acts or

omissions of any of its member firms nor can it control the exercise of their professional judgment

or bind them in any way. No member firm is responsible or liable for the acts or omissions of any

other member firm nor can it control the exercise of another member firm's professi

or bind another member firm or PwCIL in any way.

been prepared for and only for in accordance with the terms of the specific contract

533/SI2.613513 dated 19/12/2011 under Service Framework Contract

and for no other purpose. We do not accept or assume any liability or duty

of care for any other purpose or to any other person to whom this report is shown or into whose

hands it may come save where expressly agreed by our prior consent in writing.

PricewaterhouseCoopers. All rights reserved. "PricewaterhouseCoopers" and "PwC" refer to

the network of member firms of PricewaterhouseCoopers International Limited (PwCIL). Each

member firm is a separate legal entity and does not act as agent of PwCIL or any other member firm.

PwCIL does not provide any services to clients. PwCIL is not responsible or liable for the acts or

ember firms nor can it control the exercise of their professional judgment

or bind them in any way. No member firm is responsible or liable for the acts or omissions of any

other member firm nor can it control the exercise of another member firm's professional judgment

or bind another member firm or PwCIL in any way.

142

Documents

20120629 REMIT FinalReport - European Commission · 5 4.5.2.2. Records of transactions 75 4.5.2.3. List of contracts and derivatives and appropriate de minimis thresholds 75 4.5.2.4